Fri, 01 Mar 2013

Pembina Pipeline Corporation announces fourth quarter and annual results

Record adjusted EBITDA and adjusted cash flow from operating activities per share

All financial figures are in Canadian dollars unless noted otherwise. This report contains forward-looking statements and information that are based on Pembina Pipeline Corporation's ("Pembina" or the "Company") current expectations, estimates, projections and assumptions in light of its experience and its perception of historic trends. Actual results may differ materially from those expressed or implied by these forward-looking statements. Please see "Forward-Looking Statements & Information" in the accompanying Management's Discussion & Analysis ("MD&A") for more details. This report also refers to financial measures that are not defined by Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP Measures" of the accompanying MD&A.

CALGARY, Mar. 1, 2013 /CNW/ - On April 2, 2012 Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the three and twelve month periods ending December 31, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012. together with results of Legacy Pembina excluding Provident ("Legacy Pembina"), from January 1 through April 1, 2012, if applicable. The comparative figures reflect solely the 2011 results of Legacy Pembina. For further information with respect to the Acquisition, please refer to Note 5 of the Consolidated Financial Statements for the year ended December 31, 2012.

Financial & Operating Overview


($ millions, except where noted)	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
	2012	2011	2012	2011
Revenue	1,265.7	468.1	3,427.4	1,676.0
Operating margin⁽¹⁾	222.1	105.9	676.2	417.1
Gross profit	172.1	87.2	538.7	354.3
Earnings for the period	81.3	45.0	225.0	165.7
Earnings per share - basic and diluted (dollars)	0.28	0.27	0.87	0.99
Adjusted EBITDA⁽¹⁾	199.0	88.2	590.1	368.6
Cash flow from operating activities	139.5	73.8	359.8	285.5
Adjusted cash flow from operating activities⁽¹⁾	172.3	66.0	493.8	305.8
Adjusted cash flow from operating activities per share⁽¹⁾	0.59	0.39	1.91	1.83
Dividends declared	118.4	65.4	417.6	261.2
Dividends per common share (dollars)	0.41	0.39	1.61	1.56

⁽¹⁾ Refer to "Non-GAAP Measures."

Fourth Quarter and Year End 2012 Financial Highlights

Consolidated operating margin during the fourth quarter of 2012 increased to $222.1 million compared to $105.9 million during the same period of the prior year. Full year operating margin totalled $676.2 million compared to $417.1 million in 2011. Both the 2012 fourth quarter and full year operating margin were the highest in the Company's history. Operating margin is a non-GAAP measure; see "Non-GAAP Measures."
During the fourth quarter of 2012, Pembina generated operating margin of $57.9 million from its Conventional Pipelines business, $29.6 million from Oil Sands & Heavy Oil and $14.4 million from Gas Services. For these three businesses, operating margin was positively impacted by increased volumes, as discussed below, and gas processed through Pembina's new Musreau deep cut facility. The Company's Midstream business also saw a significant increase in operating margin to $119.5 million, which includes results generated by the assets acquired through the Acquisition. The performance of Pembina's Midstream business was somewhat tempered by a continued soft NGL pricing environment. These softer prices resulted from excess industry inventory levels due to decreased propane demand, which was caused by the relatively warm 2011/12 winter across North America and a mild start to the 2012/2013 winter season.
For the full year of 2012, operating margin generated by Pembina's businesses was as follows: Conventional Pipelines increased to $209.3 million compared to $181.5 million in 2011; Oil Sands & Heavy Oil contributed $116.8 million compared to $90.9 million during the prior year; Gas Services totalled $59 million for 2012 compared to $49.1 million in 2011; and Midstream's operating margin for 2012 was $288.5 million compared to $93.2 million in the previous year. The significant variance in Midstream's operating margin is primarily due to results generated by the acquired Provident assets.
Operationally, Pembina experienced one of the strongest years in its history. Conventional Pipelines transported an average of 456.3 mbpd in 2012, 10 percent more than 2011 when average volumes were 413.9 mbpd. Notably, fourth quarter 2012 volumes in this business averaged 480.2 mbpd, an increase of almost 14 percent over the fourth quarter of 2011. Gas Services also saw an increase in volumes of 8 percent, with the Cutbank Complex processing an average of 275.2 MMcf/d during 2012 compared to 253.8 MMcf/d in 2011.
The Company's earnings were $81.3 million ($0.28 per share) for the fourth quarter of 2012 compared to $45 million ($0.27 per share) for the fourth quarter of 2011. Earnings were $225 million ($0.87 per share) for the year ended December 31, 2012 compared to $165.7 million ($0.99 per share) during the same period of 2011. These increases were due to both the Acquisition as well as increased volumes transported and processed, as mentioned above, and were impacted by unrealized gains/losses on commodity-related derivative financial instruments. Per share metrics were also impacted by the Acquisition.
Pembina generated record adjusted EBITDA of $199 million during the fourth quarter of 2012 compared to $88.2 million during the fourth quarter of 2011 (adjusted EBITDA is a non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the year ended December 31, 2012 was $590.1 million compared to $368.6 million for 2011. The increase in quarterly and full year 2012 adjusted EBITDA was due to strong results from each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the completion of the Acquisition.
Cash flow from operating activities was $139.5 million ($0.48 per share) for the fourth quarter of 2012 compared to $73.8 million ($0.44 per share) for the same period in 2011, and was $359.8 million ($1.39 per share) for the year ended December 31, 2012 compared to $285.5 million ($1.71 per share) during the prior year. These increases were primarily due to higher EBITDA, which was somewhat offset by acquisition-related expenses, higher interest expenses and an increase in working capital which was partially associated with the integration of Provident.
Adjusted cash flow from operating activities was a record $172.3 million ($0.59 per share) for the fourth quarter of 2012 compared to $66 million ($0.39 per share) for the fourth quarter of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). For the full year, adjusted cash flow from operating activities was the highest in the Company's history at $493.8 million ($1.91 per share) in 2012 compared to $305.8 million ($1.83 per share) in 2011.
As of April 2, 2012, following the close of the Acquisition, the Company increased its monthly dividend rate by 3.8 percent to $0.135 per share per month (or $1.62 annualized) from $0.13 per share per month (or $1.56 annualized). This marks the ninth dividend increase since Pembina began trading publicly in 1997.

2012 Year in Review & Growth Update

2012 marked a pivotal year in Pembina's history. With the Acquisition of Provident in April of 2012, Pembina launched a new chapter as a much larger, more financially flexible and diversified company. With assets along the majority of the liquids hydrocarbon value chain, Pembina is now a truly integrated energy infrastructure company with the scale and scope necessary to meet the growing needs of Canada's and North America's oil and gas industry. The Acquisition provided for a stronger balance sheet, more robust cash flow and the ability to strategically pursue larger, more complex growth projects. Pembina is very well positioned from a geological perspective to capture the broader range of opportunities resulting from the Acquisition.

Integration of Provident's assets, business processes and procedures is substantially complete. Pembina is now operating on a single enterprise-wide financial system and all staff are integrated within their respective departments.

While the Acquisition has brought with it new opportunities, Pembina's core focus remains unchanged: pursuing responsible growth, safe and reliable operations, and delivering long-term and sustainable returns for our shareholders. This is evident in the many growth-related accomplishments Pembina achieved throughout the year, which we expect will provide attractive cash flows in the years ahead:

Pembina has undertaken numerous expansions on its Conventional Pipeline systems to accommodate increased customer demand due to strong drilling results and increased field liquids extraction by producers in areas of Alberta including Dawson Creek, Grande Prairie, Kaybob and Fox Creek.

The expansion has been split into two phases. During the first phase, the Company completed a re-contracting initiative in 2012 on existing and new volumes on the Northern NGL System (the Peace and Northern pipelines) to underpin the system's Phase 1 NGL expansion.
The Company is nearing completion of the Phase 1 NGL expansion, which is expected to cost $30 million and add approximately 17 thousand barrels per day ("mbpd") of additional NGL capacity to the Northern NGL System in the second quarter of 2013.
The Phase 1 Peace high vapour pressure ("HVP") expansion, which requires seven new or upgraded pump stations and associated pipeline reinforcement work from west of Fox Creek to Fort Saskatchewan, will add NGL capacity of approximately 35 mbpd. Pembina expects to commission three of the pump stations by August 2013, and the remaining four stations by October 2013 at an estimated cost of $70 million.
The Phase 1 low vapour pressure ("LVP") expansion requires three upgraded pump stations and associated pipeline reinforcement work between Fox Creek and Edmonton, Alberta, and will provide an additional 40 mbpd of crude oil and condensate capacity on this segment. Pembina expects to commission one of the three pump stations by June 2013, and the remaining two stations by October 2013 at an estimated cost of $30 million.

On February 13, 2013, Pembina announced that it had reached its contractual threshold to proceed with its previously announced plans to significantly expand its crude oil and condensate throughput capacity on its Peace Pipeline system by 55 mbpd ("Phase 2 LVP Expansion"):

The Phase 2 LVP Expansion is expected to accommodate increased producer crude oil and condensate volumes due to strong drilling results in the Dawson Creek, Grande Prairie and Kaybob/Fox Creek areas of Alberta. Pembina expects the total cost of the Phase 2 LVP Expansion to be approximately $250 million (including the mainline expansion and tie-ins). Subject to obtaining regulatory and environmental approvals, Pembina anticipates being able to bring the expansion into service by late-2014. Once complete, this expansion will increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd. The Phase 2 LVP Expansion is underpinned by long-term fee-for-service agreements with area producers. The combined LVP expansions will increase capacity by 61 percent from current levels.

The Company is actively working to accelerate the timing of its second previously announced NGL expansion (a portion of which is subject to reaching commercial arrangements with its customers and receipt of environmental and regulatory approvals):

The Phase 2 NGL Expansion to the Company's Northern NGL System will increase capacity from 167 mbpd to 220 mbpd. Pembina expects this expansion to cost approximately $415 million (including the mainline expansion and tie-ins) and to be complete in early to mid-2015.

In addition, in 2012:

Pembina completed and brought into service two expansions at its existing Gas Services assets at its Cutbank Complex - the 205 MMcf/d Musreau deep cut and the 50 MMcf/d Musreau shallow cut expansion;
Pembina entered into a long-term arrangement for the remaining 50 MMcf/d of capacity at its Saturn liquids extraction facility, bringing total contracted capacity to 100 percent;
Pembina received the required environmental and regulatory approvals, and awarded construction contracts, for the pipeline portions of the Resthaven and Saturn projects and began construction on both during the fall and winter of 2012/2013;
Pembina successfully completed and commissioned an 8,000 bpd expansion at its Redwater fractionator on schedule and under budget in September 2012;
Pembina increased the capacity of its Drayton Valley pipeline (which serves the Cardium play) from 145 mbpd to 195 mbpd by refurbishing an existing pump station;
The Company began construction on a joint venture full-service terminal in the Judy Creek, Alberta area which has an estimated project completion date of April 2013; and,
In September of 2012, Pembina brought the first of seven fee-for-service caverns into service at its Redwater site. Three additional caverns are completed and Pembina is in the process of preparing them for service. Pembina expects to be able to bring two caverns into service in March 2013, and the third cavern into service in June 2013.

Pembina continues to advance preliminary engineering and work on its proposed 73 mbpd ethane plus fractionator at its Redwater site and is soliciting customer support for the project.
The Company is investigating offshore propane export opportunities that would allow it to leverage its existing assets and provide a solution for Canadian producers.

Pembina also secured financing in 2012 to support its long-term objectives. The Company increased its credit facility from $800 million prior to closing of the Acquisition to $1.5 billion post-close. This, along with the offering of $450 million of 10-year senior unsecured medium-term notes due 2022 with an annual interest rate of 3.77%, which closed in October, provides Pembina increased flexibility to pursue its capital plans.

"2012 was a very successful year for Pembina. We delivered steady operational and financial results, increased our dividend and made substantial progress on a number of capital projects across our business to support our customers and help secure returns for our investors," said Bob Michaleski, Pembina's Chief Executive Officer. "With the integration of Provident substantially complete, we are looking to the future and are excited to grow in ways that would not have been possible on a stand-alone basis. 2013 will be about demonstrating the benefits of our fully integrated platform post-Acquisition, and we've kicked the year off on the right foot with our recent announcement to proceed with our Phase 2 LVP Expansion."

"Our approved 2013 capital spending plan is the largest in the Company's history - totalling $965 million - and we are confident in our ability to execute on it," added Michaleski. "Including the 2013 capital spending plan, we have approximately $4 billion in unrisked growth opportunities which are in line with our core strengths. Our team will be focused on achieving disciplined growth and securing projects with the most attractive cash flows and return on capital, all while minimizing overall risk."

Mick Dilger, Pembina's President and Chief Operating Officer commented on Pembina's operational, safety and environmental performance during the past year: "2012 was a very successful year in terms of continuing to offer safe and reliable services. We exited the year with improved overall safety performance metrics compared to 2011, which is in part due to the initiation of a safety culture improvement project alongside our robust integrity management program. For 2013 and beyond, Pembina remains committed to being the industry neighbour of choice. That means our people are highly committed to doing the right thing each and every day and are focused on reliability, no harm to the environment and personal safety."

2012 Online Annual Report

Pembina has published an online annual report on its website at www.pembina.com under "Investor Centre" which is supplementary to its annual management's discussion and analysis, financial statements and notes. This interactive report includes an overview of 2012 results, as well as videos featuring Pembina's senior executives as they discuss the Company's future prospects.

While the online annual report will not be printed, investors and other stakeholders may obtain a hard copy of Pembina's annual management's discussion and analysis, financial statements and notes by mail by contacting Investor Relations at [email protected].

Conference Call & Webcast

Pembina will host a conference call on March 4, 2013 at 8 a.m. MT (10 a.m. ET) to discuss details related to the 2012 fourth quarter and full year. The conference call dial in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A live webcast of the conference call can be accessed on Pembina's website under "Investor Centre - Presentation & Events," or by entering http://event.on24.com/r.htm?e=570212&s=1&k=126357DBB613EBB2DF3D9565F6C32327 in your web browser.

Hedging Information

Pembina has posted updated hedging information on its website, www.pembina.com, under "Investor Centre - Hedging".

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis ("MD&A") of the financial and operating results of Pembina Pipeline Corporation ("Pembina" or the "Company") is dated March 1, 2013 and is supplementary to, and should be read in conjunction with, Pembina's audited consolidated annual financial statements for the years ended December 31, 2012 and 2011 ("Consolidated Financial Statements"). All dollar amounts contained in this MD&A are expressed in Canadian dollars unless otherwise noted.

Management is responsible for preparing the MD&A. This MD&A has been reviewed and recommended by the Audit Committee of Pembina's Board of Directors and approved by its Board of Directors.

This MD&A contains forward-looking statements (see "Forward-Looking Statements & Information") and refers to financial measures that are not defined by Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP Measures."

On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the three and twelve month periods ending December 31, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina excluding Provident ("Legacy Pembina"), from January 1 through April 1, 2012, if applicable. The comparative figures reflect solely the 2011 results of Legacy Pembina. The results of the business acquired through the Acquisition are reported as part of the Company's Midstream business. For further information with respect to the Acquisition, please refer to Note 5 of the Consolidated Financial Statements for the year ended December 31, 2012.

About Pembina

Calgary-based Pembina Pipeline Corporation is a leading transportation and midstream service provider that has been serving North America's energy industry for nearly 60 years. Pembina owns and operates: pipelines that transport conventional and synthetic crude oil and natural gas liquids produced in western Canada; oil sands, heavy oil and diluent pipelines; gas gathering and processing facilities; and, an oil and natural gas liquids infrastructure and logistics business. With facilities strategically located in western Canada and in natural gas liquids markets in eastern Canada and the U.S., Pembina also offers a full spectrum of midstream and marketing services that spans across its operations. Pembina's integrated assets and commercial operations enable it to offer services needed by the energy sector along the hydrocarbon value chain.

Pembina is a trusted member of the communities in which it operates and is committed to generating value for its investors by running its businesses in a safe, environmentally responsible manner that is respectful of community stakeholders.

Strategy

Pembina's goal is to provide highly competitive and reliable returns to investors through monthly dividends while enhancing the long-term value of its shares. To achieve this, Pembina's strategy is to:

Preserve value by providing safe, responsible, cost-effective and reliable services;
Diversify Pembina's asset base along the hydrocarbon value chain by providing integrated service offerings which enhance profitability;
Pursue projects or assets that are expected to generate increased cash flow per share and capture long-life, economic hydrocarbon reserves; and
Maintain a strong balance sheet through the application of prudent financial management to all business decisions.

Pembina is structured into four businesses: Conventional Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream, which are described in their respective sections of this MD&A.

Common Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

Measurement		Other
bbl	barrel	AECO	Alberta gas trading price
mmbbls	millions of barrels	AESO	Alberta Electric Systems Operator
bpd	barrels per day	B.C.	British Columbia
mbpd	thousands of barrels per day	DRIP	Premium Dividend™ and Dividend Reinvestment Plan
mboe/d	thousands of barrels of oil equivalent per day	Frac	Fractionation
MMcf/d	millions of cubic feet per day	IFRS	International Financial Reporting Standards
bcf/d	billions of cubic feet per day	NGL	Natural gas liquids
MW/h	megawatts per hour	NYMEX	New York Mercantile Exchange
GJ	gigajoule	NYSE	New York Stock Exchange
km	kilometre	TET	Indicates product in the Texas Eastern Products Pipeline at Mont Belvieu, Texas (Non-TET refers to product in a location at Mont Belvieu other than in the Texas Eastern Products pipeline)
		TSX	Toronto Stock Exchange
		U.S.	United States
		WCSB	Western Canadian Sedimentary Basin
		WTI	West Texas Intermediate (crude oil benchmark price)

Financial & Operating Overview


		3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except where noted)		2012	2011	2012	2011
Average throughput - Conventional Pipelines (mbpd)		480.2	422.8	456.3	413.9
Contracted capacity - Oil Sands & Heavy Oil (mbpd)		870.0	870.0	870.0	870.0
Average processing volume - Gas Services (mboe/d) net to Pembina⁽¹⁾		46.0	45.3	45.9	42.3
NGL sales volume - NGL Midstream (mbpd)		115.8		97.7⁽³⁾
Revenue		1,265.7	468.1	3,427.4	1,676.0
Operations		86.0	55.1	271.6	191.9
Cost of goods sold, including product purchases		968.6	308.0	2,475.0	1,072.3
Realized gain (loss) on commodity-related derivative financial instruments		11.0	0.9	(4.6)	5.3
Operating margin⁽²⁾		222.1	105.9	676.2	417.1
Depreciation and amortization included in operations		47.8	19.6	173.6	68.0
Unrealized gain (loss) on commodity-related derivative financial instruments		(2.2)	0.9	36.1	5.2
Gross profit		172.1	87.2	538.7	354.3
Deduct/(add)
	General and administrative expenses	27.3	21.0	97.5	62.2
	Acquisition-related and other expense	0.5	0.8	24.7	1.4
	Net finance costs	35.7	22.1	115.1	91.9
	Share of loss (profit) of investments in equity accounted investee, net of tax	0.2	(1.5)	1.1	(5.8)
Income tax expense (reduction)		27.1	(0.2)	75.3	38.9
Earnings for the period		81.3	45.0	225.0	165.7
Earnings per share - basic and diluted (dollars)		0.28	0.27	0.87	0.99
Adjusted earnings⁽²⁾		115.8	43.7	283.7	208.9
Adjusted earnings per share⁽²⁾		0.40	0.26	1.10	1.25
Adjusted EBITDA⁽²⁾		199.0	88.2	590.1	368.6
Cash flow from operating activities		139.5	73.8	359.8	285.5
Cash flow from operating activities per share		0.48	0.44	1.39	1.71
Adjusted cash flow from operating activities⁽²⁾		172.3	66.0	493.8	305.8
Adjusted cash flow from operating activities per share⁽²⁾		0.59	0.39	1.91	1.83
Dividends declared		118.4	65.4	417.6	261.2
Dividends per common share (dollars)		0.41	0.39	1.61	1.56
Capital expenditures		254.7	148.9	584.3	527.6
Total enterprise value ($ billions) ⁽²⁾		11.0	6.6	11.0	6.6
Total assets ($ billions)		8.3	3.3	8.3	3.3

⁽¹⁾ Gas Services processing volumes converted to mboe/d from MMcf/d at 6:1 ratio.

⁽²⁾ Refer to "Non-GAAP Measures."

⁽³⁾ Represents per day volumes since the closing of the Acquisition.

Revenue, net of cost of goods sold, increased over 85 percent to $297.1 million during the fourth quarter of 2012 from $160.1 million during the same period of 2011. Full year revenue, net of cost of goods sold, in 2012 was $952.4 million compared to $603.7 million in 2011. Revenue was higher in 2012 than the comparative periods in 2011 primarily due to the addition of results generated by the assets acquired through the Acquisition, which are reported in the Company's Midstream business, as well as improved performance in each of Pembina's legacy businesses, as discussed in further detail below.

Operating expenses were $86 million during the fourth quarter and $271.6 million for the full year in 2012 compared to $55.1 million and $191.9 million during the same periods in 2011. The increases were primarily due to additional costs associated with the growth in Pembina's asset base since the Acquisition and higher variable costs in each of the Company's businesses because of increased volumes.

Operating margin was $222.1 million during the fourth quarter, up almost 110 percent from the same period last year when operating margin totalled $105.9 million (operating margin is a Non-GAAP measure; see "Non-GAAP Measures"). For the year ended December 31, 2012, operating margin was $676.2 million compared to $417.1 million for the full year of 2011. These increases were primarily due to higher revenue, as discussed above.

Realized and unrealized gains/losses on commodity-related derivative financial instruments resulting from Pembina's market risk management program are primarily related to outstanding positions acquired on the closing of the Acquisition (see "Market Risk Management Program" and Note 27 to the Consolidated Financial Statements). The unrealized gain on commodity-related derivative financial instruments was $36.1 million for 2012 reflecting changes in the future NGL and natural gas price indices between April 2, 2012 and December 31, 2012 (see "Business Environment").

Depreciation and amortization (operational) increased to $47.8 million during the fourth quarter of 2012 compared to $19.6 million during the same period in 2011 and $173.6 million for the year ended December 31, 2012 compared to $68 million in 2011. Both the quarterly and full year increases reflect depreciation on new capital additions including those assets acquired through the Acquisition.

The increases in revenue and operating margin contributed to gross profit of $172.1 million during the fourth quarter and $538.7 million for the full year of 2012 compared to $87.2 million and $354.3 million for the same periods of 2011.

General and administrative expenses ("G&A") of $27.3 million were incurred during the fourth quarter of 2012 compared to $21 million during the fourth quarter of 2011. The increase, year-over-year, for the three month period was mainly due to the addition of employees who joined Pembina through the Acquisition, an increase in salaries and benefits for existing and new employees, and increased rent for expanded office space. Full year 2012 G&A totaled $97.5 million compared to $62.2 million incurred during 2011. The primary driver of the year-over-year increase in G&A was a $19.8 million increase in salaries, benefits and consulting costs, $3 million increase in rent and $3.6 million in corporate depreciation. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by $1.2 million.

Pembina generated adjusted EBITDA of $199 million during the fourth quarter of 2012 compared to $88.2 million during the fourth quarter of 2011 (adjusted EBITDA is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the full year of 2012 was $590.1 million compared to $368.6 million in 2011. The increase in quarterly and full year adjusted EBITDA was due to strong results from each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the growth of Pembina's operations since completion of the Acquisition.

The Company's earnings were $81.3 million ($0.28 per share) during the fourth quarter of 2012 compared to $45 million ($0.27 per share) during the fourth quarter of 2011 and $225 million ($0.87 per share) for the full year of 2012 compared to $165.7 million ($0.99 per share) in 2011. These increases were the result of the Acquisition of Provident as well as improved performance in each of the Company's legacy businesses. Per share metrics were also impacted by the Acquisition.

Adjusted earnings were $115.8 million ($0.40 per share) during the fourth quarter of 2012 compared to $43.7 million ($0.26 per share) during the fourth quarter of 2011 (adjusted earnings is a Non-GAAP measure; see "Non-GAAP Measures"). For the full year of 2012, adjusted earnings totalled $283.7 million ($1.10 per share) compared to $208.9 million ($1.25 per share) in 2011. The increases in adjusted earnings were primarily due to higher operating margin, as discussed above, which was partially offset by increased depreciation and amortization (operational) resulting from a larger asset base, and higher G&A and finance costs.

Cash flow from operating activities was $139.5 million ($0.48 per share) during the fourth quarter of 2012 and $359.8 million ($1.39 per share) for the full year in 2012 compared to $73.8 million ($0.44 per share) and $285.5 million ($1.71 per share), respectively, for the comparative periods of 2011. The increases in cash flow from operating activities was primarily due to an increase in adjusted EBITDA, which was somewhat offset by acquisition-related expenses, higher interest expenses and an increase in working capital, which was partially associated with the integration of Provident.

Adjusted cash flow from operating activities was $172.3 million ($0.59 per share) during the fourth quarter of 2012, an increase of more than 160 percent, compared to $66.0 million ($0.39 per share) during the fourth quarter of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted cash flow from operating activities was a record $493.8 million ($1.91 per share) during 2012 compared to $305.8 million ($1.83 per share) during 2011 and was largely driven by strong performance in each of Pembina's businesses.

Operating Results


	3 Months Ended December 31 (unaudited)				12 Months Ended December 31
	2012		2011		2012		2011
($ millions)	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾
Conventional Pipelines	99.2	57.9	75.8	41.6	338.8	209.3	296.2	181.5
Oil Sands & Heavy Oil	45.8	29.6	39.7	27.3	172.4	116.8	134.9	90.9
Gas Services	23.3	14.4	19.1	13.0	88.3	59.0	71.5	49.1
Midstream	128.8	119.5	25.5	23.4	352.9⁽³⁾	288.5⁽³⁾	101.1	93.2
Corporate		0.7		0.6		2.6		2.4
Total	297.1	222.1	160.1	105.9	952.4	676.2	603.7	417.1

⁽¹⁾	Midstream revenue is net of $975 million in cost of goods sold, including product purchases, for the quarter ended December 31, 2012 (quarter ended December 31, 2011: $308 million) and $2,494.5 million in cost of goods sold, including product purchases, for the twelve months ended December 31, 2012 (twelve months ended December 31, 2011: $1,072.3 million).
⁽²⁾	Refer to "Non-GAAP Measures."
⁽³⁾	Includes results from operations generated by the acquired assets from Provident since closing of the Acquisition on April 2, 2012.

Conventional Pipelines


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except where noted)	2012	2011	2012	2011
Average throughput (mbpd)	480.2	422.8	456.3	413.9
Revenue	99.2	75.8	338.8	296.2
Operations	42.1	35.5	129.6	119.1
Realized gain on commodity-related derivative financial instruments	0.8	1.3	0.1	4.4
Operating margin⁽¹⁾	57.9	41.6	209.3	181.5
Depreciation and amortization included in operations	7.8	11.1	44.0	41.6
Unrealized gain (loss) on commodity-related derivative financial instruments	0.8	(0.9)	(9.0)	3.7
Gross profit	50.9	29.6	156.3	143.6
Capital expenditures	88.1	24.9	187.3	72.0

⁽¹⁾Refer to "Non-GAAP Measures."

Business Overview

Pembina's Conventional Pipelines business comprises a well-maintained and strategically located 7,850 km pipeline network that extends across much of Alberta and B.C. It transports approximately half of Alberta's conventional crude oil production, about thirty percent of the NGL produced in western Canada, and virtually all of the conventional oil and condensate produced in B.C. This business' primary objective is to generate sustainable operating margin while pursuing opportunities for increased throughput and revenue. Conventional Pipelines endeavours to maintain and/or improve operating margin by capturing incremental volumes, expanding its pipeline systems, managing revenue and following a disciplined approach to its operating expenses.

Operational Performance: Throughput

During the fourth quarter of 2012, Conventional Pipelines' throughput averaged 480.2 mbpd, consisting of an average of 352.5 mbpd of crude oil and condensate and 127.7 mbpd of NGL. This was primarily due to continued production growth from regional resource plays in the Cardium (oil), Deep Basin Cretaceous (NGL), Montney (oil/NGL) and Beaverhill Lake (oil) formations and represents an increase of 14 percent compared to the same period of 2011, when average throughput was 422.8 mbpd. Producer production growth also contributed to a 10 percent increase in throughput for the full year of 2012 compared to 2011.

Financial Performance

During the fourth quarter of 2012, Conventional Pipelines generated revenue of $99.2 million compared to $75.8 million in the same quarter of the previous year. For 2012, revenue was $338.8 million compared to $296.2 million during 2011. The 31 and 14 percent increases during the respective 2012 periods were primarily due to strong volumes generated by newly connected facilities on Pembina's Conventional Pipelines systems, as well as many deliveries being received at higher toll locations along the Company's pipeline network.

Quarterly operating expenses increased to $42.1 million compared to $35.5 million in the fourth quarter of 2011 due to higher variable costs associated with increased throughput as well as integrity and geotechnical expenditures. Operating expenses for 2012 increased to $129.6 million from $119.1 million in the same period last year. This nine percent year-over-year increase was because of the same factors that impacted quarterly operating expenses.

As a result of higher revenue, operating margin for the fourth quarter of 2012 was $57.9 million compared to $41.6 million during the same period of 2011. Full year revenue in 2012, which was offset slightly by an increase in operating expenses, increased to $209.3 million compared to $181.5 million for 2011.

Depreciation and amortization included in operations was $7.8 million during the fourth quarter of 2012 compared to $11.1 million during the fourth quarter of 2011. This decrease is due to a credit made to depreciation because of a re-measurement reduction in the decommissioning provision in excess of the carrying amount of the related asset. Depreciation and amortization included in operations for the year ended December 31, 2012 was $44 million, up from $41.6 million in 2011 due to capital additions.

For the three months ended December 31, 2012, Pembina recognized an unrealized gain on commodity-related derivative financial instruments of $0.8 million compared to an unrealized loss of $0.9 million in the fourth quarter of 2011. For the full year of 2012, Pembina recognized an unrealized loss on commodity-related derivative financial instruments of $9 million compared to an unrealized gain of $3.7 million for 2011. The 2012 unrealized loss is the result of Pembina's forward fixed-price power purchase program which is designed to mitigate operating costs fluctuations.

For the three and twelve months ended December 31, 2012, gross profit was $50.9 million and $156.3 million, respectively, compared to $29.6 million and $143.6 million, respectively, during the same periods in 2011. Higher operating margin in 2012 was partially offset by increased depreciation and amortization and unrealized losses on commodity-related derivative financial instruments.

Capital expenditures for the fourth quarter of 2012 totalled $88.1 million compared to $24.9 million during the fourth quarter of 2011, and were $187.3 million during the year compared to $72 million in 2011. The majority of the spending in 2012 related to the expansion of certain pipeline assets as described below.

New Developments: Conventional Pipelines

During 2012, Pembina saw increased volumes on its Conventional Pipelines due to the continued revitalization of many of the plays near its systems. The trend towards increased exploration, drilling and production in the WCSB has escalated over the past several years, with plays such as the Alberta Deep Basin, Cardium, Montney, Swan Hills and Duvernay being further developed by producers and offering improved recoveries with the use of innovative technology. Some of these plays were once considered mature or unviable, and others were relatively unexplored; by using horizontal drilling and multi-stage hydraulic fracturing technology, these tight and previously uneconomic portions of reservoirs began to represent attractive opportunities. For Pembina, this producer activity has meant an increase in crude oil and NGL volumes transported on its Conventional Pipeline systems and the need to complete expansions of select segments to accommodate customer demand.

Pembina is pursuing numerous expansions on its Conventional Pipeline systems to accommodate the increased customer demand mentioned above in areas of Alberta including Dawson Creek, Grande Prairie, Kaybob and Fox Creek.

The expansion has been split into two phases. During the first phase, the Company completed a re-contracting initiative in 2012 on existing and new volumes on the Northern NGL System (the Peace and Northern pipelines) to underpin the system's Phase 1 NGL expansion.
The Company is nearing completion of the Phase 1 NGL expansion, which is expected to cost $30 million and add approximately 17 mbpd of additional NGL capacity to the Northern NGL System in the second quarter of 2013.
The Phase 1 Peace high vapour pressure ("HVP") expansion, which requires seven new or upgraded pump stations and associated pipeline reinforcement work from west of Fox Creek to Fort Saskatchewan, will add NGL capacity of approximately 35 mbpd. Pembina expects to commission three of the pump stations by August 2013, and the remaining four stations by October 2013 at an estimated cost of $70 million.
The Phase 1 Peace low vapour pressure ("LVP") expansion requires three upgraded pump stations and associated pipeline reinforcement work between Fox Creek and Edmonton, Alberta, and will provide an additional 40 mbpd of crude oil and condensate capacity on this segment. Pembina expects to commission one of the three pump stations by June 2013, and the remaining two stations by October 2013 at an estimated cost of $30 million.

On February 13, 2013, Pembina announced that it had reached its contractual threshold to proceed with its previously announced plans to significantly expand its crude oil and condensate throughput capacity on its Peace Pipeline system by 55 mbpd ("Phase 2 LVP Expansion"):

The Phase 2 LVP Expansion is expected to accommodate increased producer crude oil and condensate volumes due to strong drilling results in the Dawson Creek, Grande Prairie and Kaybob/Fox Creek areas of Alberta. Pembina expects the total cost of the Phase 2 LVP Expansion to be approximately $250 million (including the mainline expansion and tie-ins). Subject to obtaining regulatory and environmental approvals, Pembina anticipates being able to bring the expansion into service by late-2014. Once complete, this expansion will increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd. The Phase 2 LVP Expansion is underpinned by long-term fee-for-service agreements with area producers. The combined LVP expansions will increase capacity by 61 percent from current levels.

The Company is actively working to accelerate the timing of its second previously announced NGL expansion (a portion of which is subject to reaching commercial arrangements with its customers and receipt of environmental and regulatory approvals):

The Phase 2 NGL Expansion to the Company's Northern NGL System will increase capacity from 167 mbpd to 220 mbpd. Pembina expects this expansion to cost approximately $415 million (including the mainline expansion and tie-ins) and to be complete in early to mid-2015.

Conventional Pipelines is also constructing the pipeline components of the Company's Saturn and Resthaven gas plant projects. These two pipeline projects will gather NGL from the gas plants for delivery to Pembina's Peace Pipeline system. Pembina has received the required environmental and regulatory approvals, has awarded construction contracts and has begun construction on both projects.

Oil Sands & Heavy Oil


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except where noted)	2012	2011	2012	2011
Capacity under contract (mbpd)	870.0	870.0	870.0	870.0
Revenue	45.8	39.7	172.4	134.9
Operations	16.2	12.4	55.6	44.0
Operating margin⁽¹⁾	29.6	27.3	116.8	90.9
Depreciation and amortization included in operations	5.0	4.9	19.8	12.8
Gross profit	24.6	22.4	97.0	78.1
Capital expenditures	18.3	47.8	30.4	191.7

⁽¹⁾Refer to "Non-GAAP Measures."

Business Overview

Pembina plays an important role in supporting Alberta's oil sands and heavy oil industry. Pembina is the sole transporter of crude oil for Syncrude Canada Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources Ltd.'s Horizon Oil Sands operation (via the Horizon Pipeline) to delivery points near Edmonton, Alberta. Pembina also owns and operates the Nipisi and Mitsue Pipelines, which provide transportation for producers operating in the Pelican Lake and Peace River heavy oil regions of Alberta, and the Cheecham Lateral which transports synthetic crude to oil sands producers operating southeast of Fort McMurray, Alberta. The Oil Sands & Heavy Oil business operates approximately 1,650 km of pipeline and has 870 mbpd of capacity under long-term, extendible contracts which provide for the flow-through of operating expenses to customers. As a result, operating margin from this business is proportionate to the amount of capital invested and is predominantly not sensitive to fluctuations in operating expenses or actual throughput.

Financial Performance

The Oil Sands & Heavy Oil business realized revenue of $45.8 million in the fourth quarter of 2012 compared to $39.7 million in the fourth quarter of 2011. This 15 percent increase is primarily due to higher flow-through operating expenses as well as higher operating margin from the Syncrude and Nipisi pipelines. Full year revenue in 2012 was $172.4 million compared to $134.9 million for 2011, largely because of contributions from the Nipisi and Mitsue pipelines which were placed into service in June and July of 2011.

Operating expenses in Pembina's Oil Sands & Heavy Oil business were $16.2 million during the fourth quarter of 2012 compared to $12.4 million during the fourth quarter of 2011, and $55.6 million for the full year of 2012 compared to $44 million in 2011. These increases primarily reflect additional operating expenses related to higher volumes being transported on the Nipisi and Mitsue pipelines compared to the same periods of the prior year.

For the three and twelve months ended December 31, 2012, operating margin increased to $29.6 million and $116.8 million compared to $27.3 million and $90.9 million, respectively, during the same periods in 2011. This is primarily due to incremental contribution from the Nipisi and Mitsue pipelines.

Depreciation and amortization included in operations for the fourth quarter of 2012 totalled $5 million compared to $4.9 million during the same period of the prior year, and $19.8 million for the twelve months of 2012 compared to $12.8 million during 2011. These increases primarily reflect the additional Nipisi and Mitsue depreciation and amortization included in operations.

For the three and twelve months ended December 31, 2012, gross profit was $24.6 million and $97 million, primarily due to higher operating margin as discussed above, compared to $22.4 million and $78.1 million, respectively, during the same periods of 2011.

For the year ended December 31, 2012, capital expenditures within the Oil Sands & Heavy Oil business totalled $30.4 million and were primarily related to Nipisi and Mitsue post-construction clean-up costs and the construction of additional pump stations on these pipelines. This compares to $191.7 million spent during the same period in 2011, the majority of which related to completing the two projects.

New Developments: Oil Sands & Heavy Oil

In 2013, Pembina plans to spend approximately $45 million to increase capacity on the Nipisi and Mitsue pipelines by 12 mbpd and 4 mbpd, respectively, while also increasing connectivity in the Edmonton area.

Pembina continues to actively work with customers on oil sands and heavy oil related solutions. With the Acquisition of Provident, the Company has increased its access to diluent supply and can offer customers condensate and butane products from various sources including Pembina's conventional pipeline systems, the Redwater fractionator, rail imports and truck racks.

Gas Services


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except where noted)	2012	2011	2012	2011
Average processing volume (MMcf/d) net to Pembina	276.0	271.5	275.2	253.8
Average processing volume (mboe/d) ⁽¹⁾ net to Pembina	46.0	45.3	45.9	42.3
Revenue	23.3	19.1	88.3	71.5
Operations	8.9	6.1	29.3	22.4
Operating margin⁽²⁾	14.4	13.0	59.0	49.1
Depreciation and amortization included in operations	3.7	2.6	14.5	9.9
Gross profit	10.7	10.4	44.5	39.2
Capital expenditures	77.2	66.4	162.8	136.5

⁽¹⁾Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio.

⁽²⁾Refer to "Non-GAAP Measures."

Business Overview

Pembina's operations include a growing natural gas gathering and processing business. Located approximately 100 km south of Grande Prairie, Alberta, Pembina's key revenue-generating Gas Services assets form the Cutbank Complex which comprises three sweet gas processing plants with 425 MMcf/d of processing capacity (368 MMcf/d net to Pembina), a 205 MMcf/d ethane plus extraction facility, as well as approximately 350 km of gathering pipelines. The Cutbank Complex is connected to Pembina's Peace Pipeline system and serves an active exploration and production area in the WCSB. Pembina has initiated construction on two projects in its Gas Services business, the Saturn and Resthaven enhanced NGL extraction facilities, to meet the growing needs of producers in west central Alberta.

Financial Performance

Gas Services recorded an increase in revenue of 22 percent during the fourth quarter of 2012, contributing $23.3 million compared to $19.1 million in the fourth quarter of 2011. For the full year of 2012, revenue was $88.3 million compared to $71.5 million in 2011. These increases primarily reflect higher processing volumes at Pembina's Cutbank Complex. Average processing volumes, net to Pembina, were 276 MMcf/d during the fourth quarter of 2012, approximately 2 percent higher than the 271.5 MMcf/d processed during the fourth quarter of the previous year. Full year volumes averaged 275.2 MMcf/d, up approximately 8 percent from 2011 when average volumes were 253.8 MMcf/d.

During the fourth quarter of 2012, operating expenses were $8.9 million compared to $6.1 million incurred in the fourth quarter of 2011. Full year operating expenses in 2012 totalled $29.3 million, up from $22.4 million during the prior year. The quarterly and full year increases were mainly due to variable costs incurred to process higher volumes at the Cutbank Complex as well as additional costs associated with running the Musreau shallow cut expansion and deep cut facilities.

As a result of processing higher volumes at the Cutbank Complex and additional processing associated with the Musreau deep cut facility, Gas Services realized operating margin of $14.4 million in the fourth quarter compared to $13 million during the same period of the prior year. On a full year basis, Gas Services generated $59 million in operating margin in 2012 compared to $49.1 million in 2011. Of the $9.9 million increase, the Musreau deep cut facility contributed $6.7 million.

Depreciation and amortization included in operations during the fourth quarter of 2012 totalled $3.7 million, up from $2.6 million during the same period of the prior year, primarily due to higher in-service capital balances from additions to the Cutbank Complex (including the Musreau feep cut facility and shallow cut expansion). For the same reason, depreciation and amortization included in operations totalled $14.5 million in 2012 compared to $9.9 million in 2011.

For the three months ended December 31, 2012, gross profit was $10.7 million compared to $10.4 million in the same period of 2011, and was $44.5 million for the full year of 2012 compared to $39.2 million in 2011. These increases reflect higher operating margin during the periods which was partially offset by increased depreciation and amortization included in operations as discussed above.

For the year ended December 31, 2012, capital expenditures within Gas Services totalled $162.8 million compared to $136.5 million during the same period of 2011. This increase was because of the spending required to complete the Musreau deep cut facility, the expansion of the shallow cut facility at the Cutbank Complex as well as capital expenditures incurred to progress the Saturn and Resthaven enhanced NGL extraction facilities.

New Developments: Gas Services

Pembina continues to see significant growth opportunities resulting from the trend towards liquids-rich natural gas drilling and the extraction of valuable NGL from natural gas in the WCSB. Pembina expects the expansions detailed below (some of which were completed in 2012) to bring the Company's Gas Service's processing capacity to 903 MMcf/d (net). This includes enhanced NGL extraction capacity of approximately 535 MMcf/d (net). These volumes would be processed on a contracted, fee-for-service basis and are expected to result in approximately 45 mbpd of incremental NGL to be transported for additional toll revenue on Pembina's conventional pipelines by early 2014.

During the year, Pembina completed two expansions at its Musreau gas plant, part of the Cutbank Complex: the 205 MMcf/d enhanced NGL extraction deep cut facility and the 50 MMcf/d shallow cut expansion. With these two expansions in place, the Cutbank Complex now has an aggregate raw shallow gas processing capacity of 425 MMcf/d (368 MMcf/d net to Pembina), an increase of 13 percent net to Pembina.

Pembina's Gas Services business is also constructing two new fully contracted facilities and associated infrastructure: the Saturn facility - a $200 million 200 MMcf/d enhanced NGL extraction facility (includes conventional pipeline tie-ins) in the Berland area of west central Alberta; and, the Resthaven facility - a $230 million 200 MMcf/d combined shallow cut and deep cut NGL extraction facility (includes conventional pipeline tie-ins) in the Resthaven, Alberta area.

Pembina expects the Saturn facility and associated pipelines to be in service in the fourth quarter of 2013. Once operational, Pembina expects the Saturn facility will have the capacity to extract up to 13.5 mbpd of NGL.

For the Resthaven facility, Pembina is modifying and expanding an existing gas plant, and is constructing a pipeline to transport the extracted NGL from the Resthaven facility to its Peace Pipeline system. Pembina will own approximately 65 percent of the Resthaven facility and 100 percent of the NGL pipeline. Pembina expects the Resthaven facility and associated pipelines to be in service in the third quarter of 2014 due to potential scope changes from the original project. Once operational, Pembina expects the Resthaven facility will have the capacity to extract up to 13 mbpd of NGL.

Construction on both facilities is underway, with over 95 percent of the major equipment ordered and on-site at the Saturn facility and over 80 percent of the major equipment ordered for the Resthaven facility.

Midstream⁽¹⁾


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31⁽²⁾
($ millions, except where noted)	2012	2011	2012	2011
Revenue	1,103.7	333.5	2,847.4	1,173.5
Operations	19.4	1.7	59.7	8.8
Cost of goods sold, including product purchases	975.0	308.0	2,494.5	1,072.4
Realized gain (loss) on commodity related derivative financial instruments	10.2	(0.4)	(4.7)	0.9
Operating margin⁽³⁾	119.5	23.4	288.5	93.2
Depreciation and amortization included in operations	31.3	0.9	95.3	3.6
Unrealized gain (loss) on commodity-related derivative financial instruments	(3.0)	1.7	45.1	1.4
Gross profit	85.2	24.2	238.3	91.0
Capital expenditures	77.4	4.6	204.0	111.5

⁽¹⁾Share of profit from equity accounted investees not included in these results.

⁽²⁾Includes results from NGL midstream since the closing of the Acquisition.

⁽³⁾Refer to "Non-GAAP Measures."

Business Overview

Pembina offers customers a comprehensive suite of midstream products and services through its Midstream business as follows:

Crude oil midstream targets oil and diluent-related opportunities from key sites across Pembina's network, which comprises 15 truck terminals (including one capable of emulsion treating and water disposal), terminalling at downstream hub locations, storage, and the Pembina Nexus Terminal ("PNT"). PNT includes: 21 inbound pipelines connections, 13 outbound pipelines connections, an excess of 1.2 million bpd of crude oil and condensate connected to the terminal, and 310,000 barrels of surface storage.
NGL midstream, which Pembina acquired through the Acquisition, includes two NGL operating systems, Redwater West and Empress East:

The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; the recently expanded 73,000 bpd Redwater NGL fractionator, 6.8 mmbbls of cavern storage and terminalling facilities at Redwater, Alberta; and, third party fractionation capacity in Fort Saskatchewan, Alberta.
The Empress East NGL system includes a 2.1 bcf/d interest in the straddle plants at Empress, Alberta; 20,000 bpd of fractionation capacity as well as 1.1 mmbbls of cavern storage in Sarnia, Ontario; and, approximately 5 mmbbls of hydrocarbon storage at Corunna, Ontario.

Financial Performance

In the Midstream business, revenue, net of cost of goods sold, grew to $128.8 million during the fourth quarter of 2012 from $25.5 million during the fourth quarter of 2011. Full year revenue, net of cost of goods sold, in 2012 was $352.9 million compared to $101.1 million in 2011. These increases were primarily due to the addition of the NGL midstream business acquired through the Acquisition and increased activity on Pembina's pipeline systems.

Operating expenses during the fourth quarter of 2012 were $19.4 million compared to $1.7 million in the fourth quarter of 2011, and were $59.7 million for the full year 2012 compared to $8.8 million in 2011. Operating expenses for the quarter and the year were higher due to the increase in Midstream's asset base since the Acquisition.

Operating margin was $119.5 million during the fourth quarter of 2012 compared to $23.4 million during the fourth quarter of 2011. Operating margin for the 2012 year was $288.5 million compared to $93.2 million in 2011. These increases were largely due to the same factors that contributed to the increase in revenue, net of cost of goods sold, as discussed above.

Depreciation and amortization included in operations during the fourth quarter of 2012 totalled $31.3 million compared to $0.9 million during the same period of the prior year. Full year 2012 depreciation and amortization included in operations totalled $95.3 million compared to $3.6 million in 2011. Both increases reflect the additional Midstream assets since the closing of the Acquisition.

For the three months ended December 31, 2012, unrealized losses on commodity-related derivative financial instruments were $3 million. For the full year, there was a gain of $45.1 million. These amounts reflect fluctuations in the future NGL and natural gas price indices during the periods (see "Market Risk Management Program" and Note 27 to the Consolidated Financial Statements).

For the three and twelve months ended December 31, 2012, gross profit in this business increased to $85.2 million and $238.3 million, respectively, from $24.2 million and $91 million, respectively, during the same periods in 2011. This is due to the addition of assets acquired through the Acquisition and higher operating margin generated by Pembina's legacy midstream operations.

For the year ended December 31, 2012, capital expenditures within the Midstream business totalled $204 million and were primarily related to cavern development and associated infrastructure as well as fractionation capacity expansion at the Redwater facility by approximately 8,000 bpd. This compares to capital expenditures of $111.5 million during 2011, which included the acquisition of a terminalling and storage facility near Edmonton, Alberta and linefill for the Peace Pipeline.

Crude Oil Midstream

Operating margin for the Company's crude oil midstream activities during the fourth quarter of 2012 was $44.7 million compared to $23.4 million during the fourth quarter of 2011. For the year ended December 31, 2012, operating margin was $132.1 million, representing an increase of 42 percent from $93.2 million in the same period last year. Strong fourth quarter and full year 2012 results were primarily due to higher volumes and increased activity on Pembina's pipeline systems, wider margins, as well as opportunities associated with enhanced connectivity at the PNT added in the first quarter of 2012. Throughput at the crude oil midstream truck terminals increased by 18 percent compared to the end of 2011 to exit 2012 at 80,000 bpd.

NGL Midstream

Operating margin for Pembina's NGL midstream activities was $74.8 million for the fourth quarter and $156.4 million year-to-date since the closing of the Acquisition, including a $5.8 million year-to-date realized loss on commodity-related derivative financial instruments (see "Market Risk Management Program").

NGL sales volumes during the fourth quarter of 2012 were 115.8 mbpd and 97.7 mbpd since the closing of the Acquisition.

Redwater West

Redwater West purchases NGL mix from various natural gas and NGL producers and fractionates it into finished products at fractionation facilities near Fort Saskatchewan, Alberta. Redwater West also includes NGL production from the Younger NGL extraction and fractionation plant (Taylor, B.C.) that provides specification NGL to B.C. markets. Also located at the Redwater facility are Pembina's industry-leading rail-based terminal and more than 6.8 mmbbls of underground hydrocarbon cavern storage, both of which service Pembina's proprietary and customer needs. Pembina's condensate terminal is the largest of its kind in western Canada.

Operating margin during the fourth quarter of 2012, excluding realized losses from commodity-related derivative financial instruments, was $49.1 million. Year-to-date since closing of the Acquisition, operating margin, excluding realized losses from commodity-related derivative financial instruments, was $131.9 million. Realized propane margins were impacted by weak 2012 market prices and decreased gas volumes at the Younger plant during the year. Overall, Redwater West NGL sales volumes averaged 59.1 mbpd since closing of the Acquisition.

Empress East

Empress East extracts NGL mix from natural gas at the Empress straddle plants and purchases NGL mix from other producers/suppliers. Ethane and condensate are generally fractionated out of the NGL mix at Empress and sold into Alberta markets. The remaining NGL mix is transported by pipelines to Sarnia, Ontario for fractionation and storage of specification products. Propane and butane are sold into central Canadian and eastern U.S. markets. Demand for propane is seasonal; inventory generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year during the winter heating season.

Operating margin during the fourth quarter of 2012, excluding realized losses from commodity-related derivative financial instruments, was $16.5 million. Year-to-date since closing of the Acquisition, operating margin, excluding realized losses from commodity-related derivative financial instruments, was $30.3 million. Results were impacted by low sales volumes, soft 2012 propane prices and high extraction premiums, but were offset by strong refinery demand for butane and low AECO natural gas prices since the Acquisition. Overall, Empress East NGL sales volumes averaged 38.6 mbpd since closing of the Acquisition.

New Developments: Midstream

As a result of the Acquisition, Pembina's midstream asset base has grown substantially. Future prospects related to this business now span across the crude oil and NGL value chains. The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects which are expected to continue to increase its stability and predictability.

Pembina continues to advance a number of initiatives, as follows:

As part of its full service terminal ("FST") development program, Pembina will be putting two new facilities into service in 2013. This includes a joint venture FST in the Judy Creek area of Alberta to serve the production from Beaverhill Lake and Swan Hills and a second FST that serves producers in the Cynthia area west of Drayton Valley. Pembina continues to advance other prospects for approval in 2013 and development in 2014.
During 2013, Pembina will enhance the connectivity of PNT, both to third party infrastructure and to the Company's own facilities between Edmonton and Fort Saskatchewan. Pembina will be adding a truck terminal and constructing storage which will come on stream in 2015. Pembina will also commission the first phase of a crude oil rail loading facility. This latter project will capitalize on synergies between capabilities and expertise acquired with Provident and the crude oil midstream business.
During 2012, Pembina successfully completed and commissioned an 8,000 bpd expansion at the Redwater fractionator, which required a 20-day turn-around of the facility in September. The project was completed on schedule and under budget. Also at Redwater, Pembina is currently in discussions with customers and completing preliminary engineering work to advance its proposed new 73,000 bpd ethane plus fractionator at its site. This fractionator would essentially duplicate the existing fractionator, and is being pursued by the Company to help ease anticipated fractionation capacity constraints in the Fort Saskatchewan, Alberta area.
In September of 2012, Pembina brought the first of seven fee-for-service caverns into service at its Redwater site. Three additional caverns are completed and Pembina is in the process of preparing them for service. Pembina expects to be able to bring two caverns into service in March 2013, and the third cavern into service in June 2013.
During the second quarter, Pembina entered into an agreement with a joint venture partner and a third-party producer to tie in its production of up to 60 MMcf/d and backstop a $12 million natural gas lateral connection to the Younger plant by the first quarter of 2013. Pembina's share of NGL extracted from this expanded gathering footprint will be incremental supply to Pembina's marketing portfolio in both Taylor, B.C. and Fort Saskatchewan, Alberta.
Given the oversupply of propane in western Canada and North America at large, and the associated pricing imbalance, Pembina is investigating opportunities for offshore propane export which would leverage its existing assets and help provide a solution for Canadian producers.

Market Risk Management Program

Pembina is exposed to frac spread risk, which is the difference between the selling price for propane-plus liquids and the input cost of natural gas required to produce respective NGL products. Pembina has a risk management program and uses derivative financial instruments to mitigate frac spread risk, when possible, to safeguard a base level of operating cash flow that covers the input cost of natural gas. Pembina has entered into derivative financial swap contracts to protect the frac spread and product margin, and to manage exposure to power costs, interest rates and foreign exchange rates.

Pembina's credit policy mitigates risk of non-performance by counterparties of its derivative financial instruments. Activities undertaken to reduce risk include: regularly monitoring counterparty exposure to approved credit limits; financial reviews of all active counterparties; entering into International Swap Dealers Association agreements; and, obtaining financial assurances where warranted. In addition, Pembina has a diversified base of available counterparties.

Management continues to actively monitor commodity price risk and mitigate its impact through financial risk management activities. A summary of Pembina's current financial derivative positions is available on Pembina's website at www.pembina.com.

A summary of Pembina's risk management contracts executed during the fourth quarter of 2012 is contained in the following table:

Transactions entered into during the fourth quarter


Year	Commodity	Description	Volume (Buy)/Sell		Effective Period
2013	Natural Gas	CDN $3.29 per gj⁽¹⁾⁽⁶⁾	(19,500)	gjpd	April 1 - October 31
	Crude Oil	US $89.32 per bbl⁽²⁾⁽⁶⁾	675	bpd	April 1 - October 31
		CDN $86.43 per bbl⁽²⁾⁽⁸⁾	10,150	bpd	January 1 - January 31
	Propane	US $0.955 per gallon⁽³⁾⁽⁶⁾	528	bpd	April 1 - December 31
	Normal Butane	US $1.507 per gallon⁽⁴⁾⁽⁶⁾	500	bpd	April 1 - October 31
	ISO Butane	US $1.636 per gallon⁽⁵⁾⁽⁶⁾	250	bpd	April 1 - October 31
	Foreign Exchange	Sell US $8,400,000 @ 0.9956⁽⁷⁾			April 1 - October 31
		Sell US $20,850,000 @ 0.9979⁽⁷⁾			April 1 - December 31
2014	Propane	US $0.955 per gallon⁽³⁾⁽⁶⁾	745	bpd	January 1 - March 31
2014	Foreign Exchange	Sell US $2,700,000 @ 0.9979⁽⁷⁾			January 1 - March 31

⁽¹⁾	Natural gas contracts are settled against Canadian Gas Price Reporter AECO's monthly index.
⁽²⁾	Crude oil contracts are settled against NYMEX WTI calendar average in U.S. or CDN dollars.
⁽³⁾	Propane contracts are settled against OPIS Mont Belvieu C3 TET.
⁽⁴⁾	Normal butane contracts are settled against OPIS Mont Belvieu NC4 NON TET.
⁽⁵⁾	ISO butane contracts are settled against OPIS Mont Belvieu IC4 NON TET.
⁽⁶⁾	Frac spread contracts entered into to manage revenue and costs associated with natural gas based supply arrangements.
⁽⁷⁾	U.S. dollar forward contracts are settled against the Bank of Canada noon rate average. Selling notional U.S. dollars for Canadian dollars at a fixed exchange rate results in a fixed Canadian dollar price for the underlying commodity.
⁽⁸⁾	Product margin contracts entered into to protect margins on commodity contracts.

The following table summarizes the impact of commodity-related derivative financial contracts settled during 2012 and 2011 which were included in the realized gain/loss on commodity-related derivative financial instruments:


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions)	2012	2011	2012	2011
Realized gain (loss) on commodity-related derivative financial instruments
Frac spread related	5.7		(4.5)
Product margin	4.2	(0.4)	(0.2)	0.9
Power	1.1	1.3	0.1	4.4
Realized gain (loss) on commodity-related derivative financial instruments	11.0	0.9	(4.6)	5.3

The realized gain on commodity-related derivative financial instruments for the fourth quarter of 2012 was $11 million compared to a realized gain of $0.9 million in the comparable period of 2011. The majority of the realized gain in the fourth quarter of 2012 was driven by NGL derivative sales contracts settling at contracted prices higher than the current NGL market prices during the settlement period and was partially offset by natural gas derivative purchase contracts settling at contracted prices higher than the market natural gas prices during the settlement period. For the year ended December 31, 2012, the Company recognized a realized loss on commodity-related derivative financial instruments of $4.6 million which reflects natural gas derivative purchase contracts settling at contracted prices higher than the market natural gas prices during the settlement period.

For more information on financial instruments and financial risk management, see Note 27 to the Consolidated Financial Statements.

Business Environment


	3 Months Ended December 31			12 Months Ended December 31
	2012	2011	% Change	2012	2011	% Change
WTI crude oil (U.S. $ per bbl)	$88.18	$94.06	(6)	$94.21	$95.12	(1)
Exchange rate (from U.S.$ to Cdn$)	$0.99	$1.03	3	$1.00	$0.99	(1)
WTI crude oil (expressed in Cdn$ per bbl)	$87.31	$96.68	(10)	$94.12	$94.21

AECO natural gas index (Cdn$ per GJ)	$2.90	$3.29	(12)	$2.28	$3.48	(34)

Mont Belvieu Propane (U.S.$ per U.S. gallon)	$0.88	$1.44	(39)	$1.00	$1.47	(32)
Mont Belvieu Propane expressed as a percentage of WTI	42%	64%	(34)	45%	65%	(31)

Market Frac Spread in Cdn$ per bbl⁽¹⁾	$38.61	$58.41	(34)	$44.70	$54.67	(18)

⁽¹⁾	Market frac spread is determined using average spot prices at Mont Belvieu, weighted based on 65 percent propane, 25 percent butane and 10 percent condensate, and the AECO monthly index price for natural gas.

Overall, weaker commodity markets impacted the performance of broader market indices. During the fourth quarter of 2012, the S&P TSX Composite Index saw a one percent increase compared to the previous quarter, with the value of the Index also realizing a four percent increase over 2011.

The Canadian dollar declined modestly against the U.S. dollar during most of the fourth quarter, averaging $0.99 per U.S. dollar; however, it was stronger than an average value of $1.03 per U.S. dollar during the fourth quarter of 2011.

With respect to commodity prices:

The benchmark WTI oil price exited 2012 at U.S. $91.82/bbl, with prices remaining range-bound after recovering from lows set earlier in the year. The Canadian heavy crude oil benchmark differential, Western Canadian Select, compared to WTI widened significantly in the fourth quarter as infrastructure constraints were aggravated by continued production growth from the WCSB. Compared to $17.17 per barrel differential in 2011, the Western Canadian Select differential averaged $25.23 in 2012.
Natural gas prices posted strong gains in the fourth quarter as more seasonal temperatures returned to North America. An abnormally warm 2011/2012 winter depressed pricing through the first half of 2012 resulting in a full year average of $2.28 compared to $3.48 in 2011. While low natural gas prices are generally favourable for NGL extraction and fractionation economics, a sustained low gas price could impact the availability and overall cost of natural gas and NGL mix supply in western Canada with the potential for natural gas producers to elect to shut-in production or reduce drilling activities.
NGL prices in the fourth quarter of 2012 were mixed across products and continued to be negatively impacted by a warm 2011/2012 winter and increasing production. This resulted in a North American supply-demand imbalance.

In the U.S., industry propane/propylene inventories were approximately 66.7 million barrels at the end of 2012 (approximately 15.9 million barrels or 31 percent above the five-year historical average for this period).
In Canada, industry propane inventories increased to 8.7 million barrels at the end of 2012 (2.5 million barrels, or 40 percent higher, than the historic five-year average).
This over-supply continues to exert pressure on prices, where the Mont Belvieu propane price averaged U.S. $0.88 per U.S. gallon (42 percent of WTI) in the fourth quarter of 2012 and U.S. $1.00 per U.S. gallon (44 percent of WTI) for the full year, significantly below its five-year average of 58 percent of WTI.
Butane and condensate sales prices were robust in the fourth quarter; however, price levels remained below those of 2011.
Market frac spreads averaged $38.61 per barrel and $44.70 per barrel during the fourth quarter and full year of 2012, respectively, compared to $58.41 per barrel and $54.67 per barrel during the same periods of the prior year. The market frac spread does not include extraction premiums, operating/transportation/storage costs and regional sales prices.

The outlook for the energy infrastructure sector in the WCSB remains positive for all of Pembina's businesses. Strong activity levels within the oil sands region represent opportunities for the Company to leverage existing assets to capitalize on additional growth opportunities. Pembina also continues to benefit from the combination of relatively high oil prices and low natural gas prices, which has resulted in oil and gas producers continuing to extract the liquids value from their natural gas production and favouring liquids-rich natural gas plays over dry natural gas. Pembina's Conventional Pipelines, Gas Services and Midstream businesses are well-positioned to capitalize on the increased activity levels in key NGL-rich producing basins. Crude oil and NGL plays being developed in the vicinity of Pembina's pipelines include the Cardium, Montney, Cretaceous, Duvernay and Swan Hills. While recent weaknesses in NGL prices and crude oil differentials as well as an inflationary cost environment have resulted in some producers scaling back activity in the WCSB, Pembina expects to see a continued positive growth profile for energy infrastructure.

Non-Operating Expenses

G&A

Pembina incurred G&A (including corporate depreciation and amortization) of $27.3 million during the fourth quarter of 2012 compared to $21 million during the fourth quarter of 2011. G&A for the year was $97.5 million compared to $62.2 million in 2011. The increase in G&A compared to the prior year is mainly due to the addition of employees who joined Pembina through the Acquisition, an increase in salaries and benefits for existing and new employees, and increased rent for expanded office space. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by $1.2 million.

Depreciation & Amortization (operational)

Operational depreciation and amortization increased to $47.8 million during the fourth quarter of 2012 compared to $19.6 million during the same period in 2011. For the year ended December 31, 2012, operational depreciation and amortization was $173.6 million, up from $68 million last year. Both increases reflect depreciation on new property, plant and equipment and depreciable intangibles including those assets acquired through the Acquisition.

Acquisition-Related and Other

Acquisition-related and other expenses during the fourth quarter of 2012 were $0.5 million compared to $0.8 million in 2011. For the year ended December 31, 2012, acquisition-related and other expenses were $24.7 million which includes acquisition expenses of $15.9 million and $8.2 million due to the required make whole payment for the redemption of the senior secured notes from the first quarter of the year. See "Liquidity and Capital Resources."

Net Finance Costs

Net finance costs in the fourth quarter of 2012 were $35.7 million compared to $22.1 million in the fourth quarter of 2011. Net finance costs for the full year of 2012 totalled $115.1 million compared to $91.9 million in 2011. The increases primarily relate to a $16.2 million year-over-year increase in loans and borrowings interest expense due to higher debt balances and an increase in interest on convertible debentures totalling $17.9 million, due to the debentures assumed on closing of the Acquisition. These factors were offset by an $11.7 million increase in the change in the fair value of non-commodity-related derivative financial instruments for the year when compared to the same period in 2011. (See Notes 21 and 27 to the Consolidated Financial Statements for the year ended December 31, 2012.) Beginning in the second quarter of 2012, the change in fair value of commodity-related derivative financial instruments was reclassified from net finance costs to gain/loss on commodity-related derivative financial instruments and is included in operational results.

Income Tax Expense

Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities. An income tax expense of $27.1 million was recorded in the fourth quarter of 2012 compared to a reduction of $0.2 million in the fourth quarter of 2011. Income tax expense in 2012 totalled $75.3 million compared to $38.9 million in 2011, which includes changes in estimates from the prior year.

Pension Liability

Pembina maintains a defined contribution plan and non-contributory defined benefit pension plans covering employees and retirees. The defined benefit plans include a funded registered plan for all employees and an unfunded supplemental retirement plan for those employees affected by the Canada Revenue Agency maximum pension limits. At the end of 2012, the pension plans carried a deficit of $27.6 million compared to a deficit of $15.8 million at the end of 2011. At December 31, 2012, plan obligations amounted to $128 million (2011: $105.2 million) compared to plan assets of $100.4 million (2011: $89.4 million). In 2012, the pension plans' expense was $7.2 million (2011: $4.7 million). Contributions to the pension plans totaled $10 million in 2012 and $8 million in 2011.

In 2013, contributions to the pension plans are expected to be $12.6 million and pension plans' expenses are anticipated to be $10.6 million. Management anticipates a long-term return on the pension plans' assets of 5.8 percent and an annual increase in compensation of 4 percent, which are consistent with current industry standards.

Liquidity & Capital Resources


($ millions)		December 31, 2012	December 31, 2011
Working capital		62.7	(343.7)⁽¹⁾
Variable rate debt⁽²⁾
	Bank debt	525.0	313.8
	Variable rate debt swapped to fixed	(380.0)	(200.0)
Total variable rate debt outstanding (average rate of 2.94%)		145.0	113.8
Fixed rate debt⁽²⁾
	Senior secured notes		58.0
	Senior unsecured notes	642.0	642.0
	Senior unsecured term debt	75.0	75.0
	Senior unsecured medium-term note 1	250.0	250.0
	Senior unsecured medium-term note 2	450.0
	Subsidiary debt	9.3
	Variable rate debt swapped to fixed	380.0	200.0
Total fixed rate debt outstanding (average of 4.90%)		1,806.3	1,225.0
Convertible debentures⁽²⁾		644.3	299.8
Finance lease liability		5.8	5.6
Total debt and debentures outstanding		2,601.4	1,644.2
Cash and unutilized debt facilities		1,032.3	235.1

⁽¹⁾As at December 31, 2011, working capital includes $310 million of current, non-revolving, unsecured credit facilities.

⁽²⁾Face value.

Pembina anticipates cash flow from operating activities will be more than sufficient to meet its short-term operating obligations and fund its targeted dividend level. In the short-term, Pembina expects to source funds required for capital projects from cash and cash equivalents and unutilized debt facilities totalling $1,032.3 million as at December 31, 2012. In addition, based on its successful access to financing in the debt and equity markets during the past several years, Pembina believes it would likely continue to have access to funds at attractive rates. Pembina also has reinstated its DRIP as of the January 25, 2012 dividend record date to help fund its ongoing capital program (see "Trading Activity and Total Enterprise Value" for further details). Management remains satisfied that the leverage employed in Pembina's capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base.

Management may make adjustments to Pembina's capital structure as a result of changes in economic conditions or the risk characteristics of the underlying assets. To maintain or modify Pembina's capital structure in the future, Pembina may renegotiate new debt terms, repay existing debt, seek new borrowing and/or issue equity.

In connection with the closing of the Acquisition on April 2, 2012, Pembina increased its $800 million facility to $1.5 billion for a term of five years. Upon closing of the Acquisition, Pembina used the facility, in part, to repay Provident's revolving term credit facility of $205 million. Further, Pembina renegotiated its operating facility to $30 million from $50 million.

Pembina's credit facilities at December 31, 2012 consisted of an unsecured $1.5 billion revolving credit facility due March 2017 and an operating facility of $30 million due July 2013. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil percent to 1.25 percent or Bankers' Acceptances rates plus 1.00 percent to 2.25 percent. Margins on the credit facilities are based on the credit rating of Pembina's senior unsecured debt. There are no repayments due over the term of these facilities. As at December 31, 2012, Pembina had $525 million drawn on bank debt, $0.1 million in letters of credit and $27.3 million in cash, leaving $1,032.3 million of unutilized debt facilities on the $1,530 million of established bank facilities. Pembina also had an additional $14.3 million in letters of credit issued in a separate demand letter of credit facility. Other debt includes $75 million in senior unsecured term debt due 2014; $175 million in senior unsecured notes due 2014; $267 million in senior unsecured notes due 2019; $200 million in senior unsecured notes due 2021; $250 million in senior unsecured medium-term notes due 2021; and $450 million in senior unsecured medium-term notes due 2022. On April 30, 2012, the senior secured notes were redeemed. Pembina has recognized $8.2 million due to the associated make whole payment, which has been included in acquisition-related and other expenses in the first quarter of the year. At December 31, 2012, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,951.3 million. Pembina's senior debt to total capital at December 31, 2012 was 28 percent.

Offering of Medium-Term Notes

On October 22, 2012, Pembina closed the offering of $450 million principal amount of senior unsecured medium-term notes ("Notes"). The Notes have a fixed interest rate of 3.77% per annum, paid semi-annually, and will mature on October 24, 2022. The net proceeds from the offering of the Notes were used to repay a portion of Pembina's existing credit facility. Standard & Poor's Rating Services ("S&P") and DBRS Limited ("DBRS") have assigned credit ratings of BBB to the Notes.

Credit Ratings

The following information with respect to Pembina's credit ratings is provided as it relates to Pembina's financing costs and liquidity. Specifically, credit ratings affect Pembina's ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current ratings on Pembina's debt by its rating agencies, particularly a downgrade below investment grade ratings, could adversely affect Pembina's cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect Pembina's ability to, and the associated costs of, entering into normal course derivative or hedging transactions. Credit ratings are intended to provide investors with an independent measure of credit quality of any issues of securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. Any rating may not remain in effect for a given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgement circumstances so warrant.

DBRS rates Pembina's senior unsecured notes 'BBB'. S&P's long-term corporate credit rating on Pembina is 'BBB'.

Assumption of rights related to the Series E and Series F Debentures

On closing of the Acquisition on April 2, 2012, Pembina assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures maturing December 31, 2017 (TSX: PPL.DB.E), and the 5.75 percent convertible unsecured subordinated debentures maturing December 31, 2018 (TSX: PPL.DB.F). Outstanding Series E and Series F debentures at April 2, 2012 were $345 million. As of December 31, 2012, $344.6 million of the debentures are still outstanding.

Capital Expenditures


		3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions)		2012	2011	2012	2011
Development capital
	Conventional Pipelines	88.1	24.9	187.3	72.0
	Oil Sands & Heavy Oil	18.3	47.8	30.4	191.7
	Gas Services	77.2	66.4	162.8	136.5
	Midstream	77.4	4.6	204.0	111.5
Corporate/other projects		(6.3)	5.2	(0.2)	15.9
Total development capital		254.7	148.9	584.3	527.6

During 2012, capital expenditures were $584.3 million compared to $527.6 million in 2011. In the comparable period in 2011, the Company's capital expenditures included the construction of the Nipisi and Mitsue pipelines, the acquisition of midstream assets in the Edmonton, Alberta area (related to PNT), linefill for the Peace Pipeline system as well as construction of the Musreau deep cut facility.

The majority of the capital expenditures in the fourth quarter and full year of 2012 were in Pembina's Conventional Pipelines, Gas Services and Midstream businesses. Conventional Pipelines' capital was incurred to progress the Northern NGL Expansion and on various new connections. Gas Services' capital was deployed to complete the Musreau deep cut facility and the expansion of the shallow cut facility at the Cutbank Complex, as well as to progress the Saturn and Resthaven enhanced NGL extraction facilities. Midstream's capital expenditures were primarily directed towards cavern development and related infrastructure as well as the 8,000 bpd expansion at the Redwater facility.

Contractual Obligations at December 31, 2012


($ millions)	Payments Due By Period
Contractual Obligations	Total	Less than 1 year	1 - 3 years	3 - 5 years	After 5 years
Operating and finance leases	293.0	25.4	55.5	58.8	153.6
Loans and borrowings⁽¹⁾	2,446.7	80.6	368.9	637.2	1,360.0
Convertible debentures⁽¹⁾	903.5	39.2	78.9	251.7	533.7
Construction commitments	362.8	324.2	38.6
Provisions⁽²⁾	361.7	0.5	5.5	25.9	330.1
Total contractual obligations	4,367.7	469.9	546.8	973.6	2,377.4

⁽¹⁾Excluding deferred financing costs.

⁽²⁾ Includes discounted constructive and legal obligations included in the decommissioning provision.

Pembina is, subject to certain conditions, contractually committed to the construction and operation of the Saturn facility and the Resthaven facility. See "Forward-Looking Statements & Information."

The contractual obligations noted above have changed significantly since December 31, 2011, due primarily to the assumption of the contractual obligations of Provident as a result of the Acquisition.

Critical Accounting Estimates

The preparation of the Consolidated Financial Statements in conformity with IFRS requires management to make judgments, estimates and assumptions that are based on the circumstances and estimates at the date of the financial statements and affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.

Judgments, estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

The following judgment and estimation uncertainties are those management considers material to the Company's financial statements:

Judgments

(i) Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make judgments about future possible events. The assumptions with respect to determining the fair value of property, plant and equipment and intangible assets acquired generally require the most judgment.

(ii) Componentization

The componentization of the Company's assets are based on management's judgment of which components constitute a significant cost in relation to the total cost of an asset and whether these components have similar or dissimilar patterns of consumption and useful lives for purposes of calculating depreciation and amortization.

(iii) Depreciation and amortization

Depreciation and amortization of property, plant and equipment and intangible assets are based on management's judgment of the most appropriate method to reflect the pattern of an asset's future economic benefit expected to be consumed by the Company. Among other factors, these judgments are based on industry standards and historical experience.

Estimates

(i) Inventory

Due to the inherent limitations in metering and the physical properties of storage caverns and pipelines, the determination of precise volumes of NGL held in inventory at such locations is subject to estimation. Actual inventories of NGL within storage caverns can only be determined by draining the caverns.

(ii) Financial derivative instruments

The Company's financial derivative instruments are recognized on the Statement of Financial Position at fair value based on management's estimate of commodity prices, share price and associated volatility, foreign exchange rates, interest rates and the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors.

(iii) Business Combinations

Estimates of future cash flows, forecast prices, interest rates and discount rates are made in determining the fair value of assets acquired and liabilities assumed for allocation of the purchase price. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities, intangibles and goodwill in the purchase price analysis. Future net earnings can be affected as a result of changes in future depreciation and amortization, asset or goodwill impairment.

(iv) Defined benefit obligations

The calculation of the defined benefit obligation is sensitive to many estimates, but most significantly the discount rate applied.

(v) Provisions and contingencies

Provisions recognized are based on management's judgment about assessing contingent liabilities and timing, scope and amount of liabilities. Management uses judgment in determining the likelihood of realization of contingent assets and liabilities to determine the outcome of contingencies.

Based on the long-term nature of the decommissioning provision, the biggest uncertainties in estimating the provision are the discount rates used, the costs that will be incurred and the timing of when these costs will occur. In addition, in determining the provision it is assumed the Company will utilize technology and materials that are currently available.

(vi) Share-based payments

Compensation costs pursuant to the share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

(vii) Deferred taxes

The calculation of the deferred tax asset or liability is based on assumptions about the timing of many taxable events and the enacted or substantively enacted rates anticipated to apply to income in the years in which temporary differences are expected to be realized or reversed.

(viii) Depreciation and amortization

Estimated useful lives of property, plant and equipment is based on management's assumptions and estimates of the physical useful lives of the assets, the economic life, which may be associated with the reserve life and commodity type of the production area, in addition to the estimated residual value.

Changes in Accounting Principles and Practices

Subsequent to the Acquisition, Pembina reviewed and compared legacy Provident's accounting policies with the Company's existing policies and determined there were no significant differences.

New standards and interpretations not yet adopted

Certain new standards, interpretations, amendments and improvements to existing standards were issued by the IASB or International Financial Reporting Interpretations Committee ("IFRIC") for accounting periods beginning after January 1, 2013. The Company has reviewed these and determined that the following:

IFRS 7 Financial Instruments: Disclosures - in December 2011, the IASB issued amendments to IFRS 7 which outline disclosures that are required for any financial assets or liabilities that are offset in accordance with IAS 32. The amendments to this standard are required to be adopted for periods beginning January 1, 2013. The adoption of these amendments is not expected to have a material impact on the Company's Financial Statements.

IFRS 9 Financial Instruments - in November 2009 and revised in October 2010 the IASB issued IFRS 9. This standard replaces the current multiple classification and measurement model for financial assets and liabilities with a proposed single model for only two classification categories: amortized cost and fair value. The standard is currently required to be adopted for periods beginning January 1, 2015. The extent of the impact of adoption of this standard has not yet been determined.

IFRS 10 Consolidated Financial Statements - in May 2011, the IASB issued IFRS 10 which provides additional guidance to determine whether an entity should be included within the consolidated financial statements of Pembina. The guidance applies to all investees, including special purpose entities. The standard is required to be adopted for periods beginning January 1, 2013. The adoption of this standard is not expected to have a material impact on the Company's Financial Statements.

IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which presents a new model for the financial reporting of joint arrangements. The new model determines whether an entity should account for joint arrangements using proportionate consolidation or the equity method with emphasis on the substance rather than legal form of a joint arrangement. The standard is required to be adopted for periods beginning January 1, 2013. The adoption of this standard is not expected to have a material impact on the Company's Financial Statements.

IFRS 12 Disclosure of Interests in Other Entities - in June 2011, the IASB issued IFRS 12 which provides guidance on the disclosure requirements for subsidiaries, joint arrangements, associates and unconsolidated structured entities. The standard is required to be adopted for periods beginning January 1, 2013. The adoption of this standard is not expected to have a material impact on the Company's Financial Statements.

IFRS 13 Fair Value Measurement - in June 2011, the IASB issued IFRS 13 to provide specific guidance for all standards where IFRS requires or permits fair value measurement. The standard defines fair value and provides guidance on disclosures about fair value measurements. The standard is required to be adopted for periods beginning January 1, 2013. The adoption of this standard is not expected to have a material impact on the Company's Financial Statements.

IAS 19 Employee Future Benefits - in June 2011, the IASB issued amendments to IAS 19 which limit the way actuarial gains and losses can be recorded and the way finance costs can be calculated, along with requirements for additional disclosures for defined benefit plans. The amendments to this standard are required to be adopted for periods beginning January 1, 2013. The adoption of these amendments is not expected to have a material impact on the Company's Financial Statements.

IAS 32 Financial Instruments: Presentation - in December 2011, the IAS issued amendments which clarify matters regarding offsetting financial assets and financial liabilities. The amendments to this standard are required to be adopted for periods beginning January 1, 2014. The Company is currently evaluating the impact that these amendments will have on its results of operations and financial position.

Controls and Procedures

As part of the requirements mandated by the Canadian securities regulatory authorities under National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"), Pembina's Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have evaluated the design and operation of Pembina's disclosure controls and procedures ("DC&P"), as such term is defined in NI 52-109, as at December 31, 2012. Based on that evaluation, the CEO and the CFO concluded that Pembina's DC&P was effective as at December 31, 2012.

The CEO and CFO are also responsible for establishing and maintaining internal controls over financial reporting ("ICFR"), as such term is defined in NI 52-109. These controls are designed to provide reasonable assurance regarding the reliability of Pembina's financial reporting and compliance with GAAP. Pembina's CEO and CFO have evaluated the design and operational effectiveness of such controls as at December 31, 2012. Based on the evaluation of the design and operating effectiveness of Pembina's ICFR, the CEO and the CFO concluded that Pembina's ICFR was effective as at December 31, 2012.

Changes in internal control over financial reporting

During 2012, there have been no changes to the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting, except as noted below.

In accordance with the provisions of NI 52-109, management, including the CEO and CFO, have limited the scope of their design of the Company's DC&P and ICFR to exclude controls, policies and procedures of Provident. Pembina acquired the assets of Provident and its subsidiaries on April 2, 2012. Provident's contribution to the Company's Consolidated Financial Statements for the quarter and year ended December 31, 2012 were approximately 36 percent and 32 percent of consolidated revenue, respectively, and approximately 11 percent and 24 percent of consolidated pre-tax earnings, respectively.

Additionally, as at December 31, 2012, Provident's current assets and current liabilities were approximately 59 percent and 44 percent of consolidated current assets and liabilities, respectively, and its non-current assets and non-current liabilities were approximately 57 percent and 34 percent of consolidated non-current assets and non-current liabilities, respectively.

The scope limitation is primarily based on the time required to assess Provident's DC&P and ICFR in a manner consistent with the Company's other operations.

Further details related to the Acquisition are disclosed in Note 5 in the Notes to the Company's Consolidated Financial Statements for the year ended December 31, 2012.

Trading Activity and Total Enterprise Value⁽¹⁾


			As at and for the 12 months ended
($ millions, except where noted)		February 26, 2013⁽²⁾	December 31, 2012	December 31, 2011
Trading volume and value
	Total volume (shares)	19,509,172	180,317,622	75,574,785
	Average daily volume (shares)	500,235	718,397	325,753
	Value traded	568.7	5,021.6	1,947.7
Shares outstanding (shares)		294,924,568	293,226,473	167,908,271
Closing share price (dollars)		28.89	28.46	29.66
Market value
	Shares	8,520.4	8,345.2	4,980.2
	5.75% convertible debentures (PPL.DB.C)	334.0⁽³⁾	332.7⁽⁴⁾	326.8⁽⁵⁾
	5.75% convertible debentures (PPL.DB.E)	205.3⁽⁶⁾	201.4⁽⁷⁾
	5.75% convertible debentures (PPL.DB.F)	193.5⁽⁸⁾	191.0⁽⁹⁾
Market capitalization		9,253.2	9,070.3	5,306.9
Senior debt		1,932.0	1,942.0	1,338.1
Total enterprise value⁽¹⁰⁾		11,185.2	11,012.3	6,645.0

⁽¹⁾ Trading information in this table reflects the activity of Pembina securities on the TSX only.

⁽²⁾ Based on 39 trading days from January 2, 2013 to February 26, 2013, inclusive.

⁽³⁾$299.7 million principal amount outstanding at a market price of $111.42 at February 26, 2013 and with a conversion price of $28.55.

⁽⁴⁾ $299.7 million principal amount outstanding at a market price of $111.00 at December 31, 2012 and with a conversion price of $28.55.

⁽⁵⁾ $300.0 million principal amount outstanding at a market price of $102.95 at December 31, 2011 and with a conversion price of $28.55.

⁽⁶⁾ $172.1 million principal amount outstanding at a market price of $119.36 at February 26, 2013 and with a conversion price of $24.94.

⁽⁷⁾$172.1 million principal amount outstanding at a market price of $117.00 at December 31, 2012 and with a conversion price of $24.94.

⁽⁸⁾$172.4 million principal amount outstanding at a market price of $112.20 at February 26, 2013 and with a conversion price of $29.53.

⁽⁹⁾$172.4 million principal amount outstanding at a market price of $110.75 at December 31, 2012 and with a conversion price of $29.53.

⁽¹⁰⁾Refer to "Non-GAAP Measures."

As indicated in the previous table, Pembina's total enterprise value was $11 billion at December 31, 2012, and the Company's issued and outstanding shares rose to 293.2 million at the end of 2012 compared to 167.9 million at the end of 2011 primarily due to shares issued pursuant to the Acquisition.

Dividends

On April 12, 2012, following closing of the Acquisition, Pembina announced a 3.8 percent increase in its monthly dividend rate to $0.135 per share per month (or $1.62 annualized) from $0.13 per share per month previously (or $1.56 annualized). Pembina is committed to providing increased shareholder returns over time by providing stable dividends and, where appropriate, further increases in Pembina's dividend, subject to compliance with applicable laws and the approval of Pembina's Board of Directors. Pembina has a history of delivering dividend increases once supportable over the long-term by the underlying fundamentals of Pembina's businesses as a result of, among other things, accretive growth projects or acquisitions (see "Forward-Looking Statements & Information").

Dividends are payable if, as, and when declared by Pembina's Board of Directors. The amount and frequency of dividends declared and payable is at the discretion of the Board of Directors which will consider earnings, capital requirements, the financial condition of Pembina and other relevant factors.

Eligible Canadian investors may benefit from an enhanced dividend tax credit afforded to the receipt of dividends, depending on individual circumstances. Dividends paid to eligible U.S. investors should qualify for the reduced rate of tax applicable to long-term capital gains but investors are encouraged to seek independent tax advice in this regard.

DRIP

Pembina reinstated its DRIP effective as of January 25, 2012. Eligible Pembina shareholders have the opportunity to receive, by reinvesting the cash dividends declared payable by Pembina on their shares, either (i) additional common shares at a discounted subscription price equal to 95 percent of the Average Market Price (as defined in the DRIP), pursuant to the "Dividend Reinvestment Component" of the DRIP, or (ii) a premium cash payment (the "Premium Dividend™") equal to 102 percent of the amount of reinvested dividends, pursuant to the "Premium Dividend™ Component" of the DRIP. Additional information about the terms and conditions of the DRIP can be found at www.pembina.com.

Participation in the DRIP for the full year of 2012 was approximately 58 percent of common shares outstanding for proceeds of approximately $218.7 million.

Listing on the NYSE

On April 2, 2012, Pembina listed its common shares, including those issued under the Acquisition, on the NYSE under the symbol "PBA."

Risk Factors

Pembina's value proposition is based on maintaining a very low risk profile. In addition to contractually eliminating the majority of its business risk, Pembina has formal risk management policies, procedures and systems designed to mitigate any residual risks, such as market price risk, credit risk and operational risk. Certain of the risks associated with Pembina's business are discussed below. For a full discussion of these and other risk factors affecting the business and operation of Pembina and its operating subsidiaries, readers are referred to Pembina's Annual Information Form, an electronic copy of which is available at www.pembina.com or on Pembina's SEDAR profile at www.sedar.com. Shareholders and prospective investors should carefully consider these risk factors before investing in Pembina's securities, as each of these risks may negatively affect the trading price of Pembina's securities, the amount of dividends paid to shareholders and the ability of Pembina to fund its debt obligations, including debt obligations under its outstanding convertible debentures and any other debt securities that Pembina may issue from time to time.

RISKS INHERENT IN PEMBINA'S BUSINESS

Operational Risks

Operational risks include: pipeline leaks, the breakdown or failure of equipment, information systems or processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); spills at truck terminals and hubs; failure to maintain adequate supplies of spare parts; operator error; labour disputes; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries which may prevent the full utilization of the Company's pipelines; and catastrophic events such as natural disasters, fires, explosions, fractures, acts of terrorists and saboteurs; and, other similar events, many of which are beyond the control of Pembina. The occurrence or continuance of any of these events could increase the cost of operating Pembina's assets or reduce revenue, thereby impacting earnings.

Pembina is committed to preserving customer and shareholder value by proactively managing operational risk through safe and reliable operations. Senior managers are responsible for the daily supervision of operational risk by ensuring appropriate policies and procedures are in place within their business units and internal controls are operating efficiently. Pembina also has an extensive program to manage system integrity, which includes the development and use of in-line inspection tools and various other leak detection technologies. Maintenance, excavation and repair programs are directed to the areas of greatest benefit, and pipe is replaced or repaired as required. Pembina also maintains comprehensive insurance coverage for significant pipeline leaks and has a comprehensive security program designed to reduce security-related risks. While Pembina feels the level of insurance is adequate, it may not be sufficient to cover all potential losses.

Midstream Business

Pembina's Midstream business includes product storage terminalling and hub services. These activities expose Pembina to certain risks including that Pembina may experience volatility in revenue due to variations in commodity prices. Primarily, Pembina enters into contracts to purchase and sell crude oil at floating market prices. The prices of products that are marketed by Pembina are subject to fluctuations as a result of such factors as seasonal demand changes, general economic conditions, changes in crude oil markets and other factors. Pembina manages its risk exposure by balancing purchases and sales to lock-in margins. Notwithstanding Pembina's management of price and quality risk, marketing margins for crude oil can vary and has varied significantly from period to period and this could have an adverse effect on the results of Pembina's commercial Midstream business and Pembina's overall results of operations. To assist in effectively smoothing that variability, Midstream is investing in assets that have a fee-based revenue component, and looking to expand this approach going forward.

The Midstream business is exposed to possible price declines between the time Pembina purchases NGL feedstock and sells NGL products, and to narrowing frac spreads. Frac spread is the difference between the selling prices for NGL products and the input cost of the natural gas required to produce the respective NGL products. The frac spread can change significantly from period to period depending on the relationship between crude oil and natural gas prices (the "frac spread ratio"), absolute commodity prices, and changes in the Canadian to U.S. dollar foreign exchange rate. There is also a differential between NGL product prices and crude oil prices which can change prices received and margins realized for midstream products separate from frac spread ratio changes. The amount of profit or loss made on the extraction portion of the NGL midstream business will generally increase or decrease with the frac spread. This exposure could result in material variability of cash flow generated by the NGL midstream business, which could negatively affect Pembina and the cash dividends of Pembina.

Reputation

Reputational risk is the potential for negative impacts that could result from the deterioration of Pembina's reputation with key stakeholders. The potential for harming Pembina's corporate reputation exists in every business decision, and all risks can have an impact on reputation, which in turn can negatively impact Pembina's business and its securities. Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, liquidity, and regulatory and legal risks must all be managed effectively to safeguard Pembina's reputation. Negative impacts from a compromised reputation could include revenue loss, reduction in customer base, delays in regulatory approvals on growth projects, and decreased value of Pembina's securities.

Pembina's reputation as a reliable and responsible energy services provider with consistent financial performance and long-term financial stability is one of its most valuable assets. Key to effectively building and maintaining Pembina's reputation is fostering a culture that promotes integrity and ethical conduct. Ultimate responsibility for Pembina's reputation lies with the executive team, who examines reputational risk and issues as part of all business decisions. Nonetheless, every employee and representative of Pembina has a responsibility to contribute in a positive way to its reputation. This means ensuring ethical practices are followed at all times, interactions with our stakeholders are positive, and compliance with applicable policies, legislation and regulations. Reputational risk is most effectively managed when every individual works continuously to protect and enhance Pembina's reputation.

Environmental Costs & Liabilities

Pembina's operations, facilities and petroleum product shipments are subject to extensive national, regional and local environmental, health and safety laws and regulations governing, among other things, discharges to air, land and water, the handling and storage of petroleum compounds and hazardous materials, waste disposal, the protection of employee health, safety and the environment, and the investigation and remediation of contamination. Pembina's facilities could experience incidents, malfunctions or other unplanned events that result in spills or emissions in excess of permitted levels and result in personal injury, fines, penalties or other sanctions and property damage. Pembina could also incur liability in the future for environmental contamination associated with past and present activities and properties. Pembina's facilities and pipelines must maintain a number of environmental and other permits from various governmental authorities in order to operate, and these facilities are subject to inspection from time to time. Failure to maintain compliance with these requirements could result in operational interruptions, fines or penalties, or the need to install potentially costly pollution control technology.

While Pembina believes its current operations are in compliance with all applicable environmental and safety regulations, there can be no assurance that substantial costs or liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, claims for damages to persons or property resulting from Pembina's operations, and the discovery of pre-existing environmental liabilities in relation to any of Pembina's existing or future properties or operations, could result in significant costs and liabilities to Pembina. In addition, the costs of environmental liabilities in relation to spill sites of which Pembina is currently aware could be greater than Pembina currently anticipates, and any such differences could be substantial. If Pembina were not able to recover the resulting costs or increased costs through insurance or increased tariffs, cash flow available to pay dividends to shareholders and to service obligations under its convertible debentures and other debt obligations could be adversely affected.

While Pembina maintains insurance in respect of damage caused by seepage or pollution in an amount it considers prudent and in accordance with industry standards, certain provisions of such insurance may limit the availability in respect of certain occurrences unless they are discovered within fixed timed periods. These periods can range from 72 hours to 30 days. Although Pembina believes it has adequate leak detection systems in place to monitor a significant spill of product, if Pembina is unaware of a problem or is unable to locate the problem within the relevant time period, insurance coverage may not be available. However, Pembina believes it has adequate leak detection systems in place to detect and monitor a significant spill.

Pembina is committed to protecting the health and safety of employees, contractors and the general public, and to sound environmental stewardship. Pembina believes that prevention of incidents and injuries, and protection of the environment, benefits everyone and delivers increased value to shareholders, customers and employees.

Pembina has health, safety and environmental management systems and established policies, programs and practices for conducting safe and environmentally sound operations. Pembina conducts regular reviews and audits to assess compliance with legislation and company policy.

Abandonment Costs

Pembina is responsible for compliance with all applicable laws and regulations regarding the abandonment of its pipeline and other assets at the end of their economic life, and these abandonment costs may be substantial. The proceeds of the disposition of certain assets associated with Pembina's pipeline systems, including, in respect of certain pipeline systems, linefill may be available to offset abandonment costs. However, it is not possible to definitively predict abandonment costs since they will be a function of regulatory requirements at the time, and the value of Pembina's assets, including linefill, may then be more or less than the abandonment costs. Pembina may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more reclamation funds to provide for payment of future abandonment costs. Such reserves could decrease cash flow available for dividends to shareholders and to service obligations under Pembina's outstanding convertible debentures and other debt obligations.

On May 26, 2009 the NEB issued its Reasons for Decision RH-2-2008 with respect to the Land Matters Consultation Initiative - Stream 3 which dealt with financial issues of pipeline abandonment for pipelines under the NEB's jurisdiction. The NEB decided in principle to set an ultimate goal to have all companies under its jurisdiction begin setting aside funds for the abandonment of pipelines no later than 5 years from the date of the decision. The NEB recommended an action plan to achieve this ultimate goal that would require pipelines to submit to the NEB preliminary cost estimates and fund collection mechanisms for pipeline abandonment prior to the setting aside of funds. In November 2011, Pembina (and formally Provident) submitted preliminary cost estimates totalling $11,350,000 to the NEB for its affected approximately 275 km segments of pipeline. Pembina is working towards a pipeline abandonment fund collection plan and set aside mechanism to present to the NEB by May 31, 2013 prior to the setting aside of funds.

Reserve Replacement, Throughput and Product Demand

Pembina's Conventional Pipeline tariff revenue is based upon a variety of tolling arrangements, including "ship or pay" contracts, cost of service arrangements and market-based tolls. As a result, certain pipeline tariff revenue is heavily dependent upon throughput levels of crude oil, NGL and condensate. Future throughput on Pembina's crude oil and NGL pipelines and replacement of oil and gas reserves in the service areas will be dependent upon the success of producers operating in those areas in exploiting their existing reserve bases and exploring for and developing additional reserves. Without reserve additions, or expansion of the service areas, throughput on such pipelines will decline over time as reserves are depleted. As oil and gas reserves are depleted, production costs may increase relative to the value of the remaining reserves in place, causing producers to shut-in production and seek lower cost alternatives for transportation. If the level of tariffs collected by Pembina decreases as a result, cash flow available for dividends to shareholders, to service obligations under the convertible debentures and the Company's other debt obligations could be adversely affected.

Over the long-term, Pembina's business will depend, in part, on the level of demand for crude oil, condensate, NGL and natural gas in the markets served by Pembina's crude oil and NGL pipelines and gas processing and gathering infrastructure in which Pembina has an interest. The global events of 2008 and 2009 had a substantial downward effect on the demand for and prices of such products. Although prices rebounded in 2010 and remained relatively strong through 2012, Pembina cannot predict the impact of future economic conditions on the energy and petrochemical industries or future demand for and prices of natural gas, crude oil, condensate and NGL. Future prices of these products are determined by supply and demand factors, including weather and general economic conditions as well as political and other conditions in other oil and natural gas regions, all of which are beyond Pembina's control.

The volumes of natural gas processed through Pembina's gas processing assets and of NGL and other products transported in the pipelines depend on production of natural gas in the areas serviced by the business and pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut-in production at lower product prices or higher production costs. Producers in the areas serviced by the business may not be successful in exploring for and developing additional reserves, and the gas plants and the pipelines may not be able to maintain existing volumes of throughput. Commodity prices may not remain at a level which encourages producers to explore for and develop additional reserves or produce existing marginal reserves. Lower production volumes will also increase the competition for natural gas supply at gas processing plants which could result in higher shrinkage premiums being paid to natural gas producers.

The rate and timing of production from proven natural gas reserves tied into the gas plants is at the discretion of the producers and is subject to regulatory constraints. The producers have no obligation to produce natural gas from these lands. Pembina's gas processing assets are connected to various third-party trunkline systems. Operational disruptions or apportionment on those third-party systems may prevent the full utilization of the business.

Over the long-term, business will depend, in part, on the level of demand for NGL and natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. Pembina cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas and NGL.

Operating and Capital Costs

Operating and capital costs of Pembina's business may vary considerably from current and forecast values and rates and represent significant components of the cost of providing service. In general, as equipment ages, costs associated with such equipment may increase over time. Dividends may be reduced if significant increases in operating or capital costs are incurred.

Although operating costs are to be recaptured through the tariffs charged on natural gas volumes processed and oil and NGL transported, respectively, to the extent such charges escalate, producers may seek lower cost alternatives or stop production of their natural gas.

Completion of the Resthaven Facility and Saturn Facility

The Resthaven facility and the Saturn facility are currently under development by Pembina and the successful completion of these facilities is dependent on numerous factors outside of Pembina's control. These factors include completion of the construction of the Resthaven facility and Saturn facility on schedule, as well as construction and labour costs that may change depending on supply, demand and/or inflation. Under the agreements governing the construction and operation of the Resthaven facility and the Saturn facility, Pembina is obligated to construct the facilities and Pembina bears the risk for its share of any cost overruns. While Pembina is not currently aware of any significant cost overruns at the date hereof, any such cost overruns in the future could reduce Pembina's expected return on the Resthaven facility and the Saturn facility and adversely affect Pembina's results of operations which, in turn, could reduce the level of cash available for dividends to shareholders.

Expansion of the Peace/Northern NGL System

The Company has announced plans to expand throughput capacity on the Peace/Northern NGL System (Phase I: 52,000, Phase 2: 55,000 bpd) and Peace Crude and Condensate System (Phase I: 40,000 bpd and Phase 2: 55,000). The successful completion of these expansions is dependent on numerous factors outside of the Company's control. These factors include receipt of regulatory approval and reaching long-term commercial arrangements with customers in respect of certain portions of the expansions, completion of the construction of the expansions on schedule, as well as construction costs that may change depending on supply, demand and/or inflation. Any agreements with customers entered into with respect to the expansions may require that the Company bears the risk for any cost overruns and any such cost overruns could reduce the Company's expected return on the expansions and adversely affect the Company's results of operations which, in turn, could reduce the level of cash available for dividends to shareholders. There is no certainty, nor can the Company provide any assurance, that regulatory approval will be received or that satisfactory commercial arrangements with customers will be reached where needed on a timely basis or at all.

Possible Failure to Realize Anticipated Benefits of Acquisitions

As part of its ongoing strategy, Pembina has completed acquisitions, such as the Provident Acquisition, and may complete additional acquisitions of assets or other entities in the future. Achieving the benefits of completed and future acquisitions depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as Pembina's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of Pembina. The integration of acquired businesses and entities requires the dedication of substantial management effort, time and resources which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect Pembina's ability to achieve the anticipated benefits of any acquisitions.

Competition

Pembina competes with other pipelines, midstream and marketing and gas processing and handling services providers in its service areas as well as other transporters of crude oil and NGL. The introduction of competing transportation alternatives into the Company's service areas could potentially have the impact of limiting the Company's ability to adjust tolls as it may deem necessary. Additionally, potential pricing differentials on the components of NGL may result in these components being transported by competing gas pipelines. Pembina believes it is prepared for and determined to meet these existing and potential competitive pressures.

Execution Risk

Pembina's ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, shortage and in-service delays. Pembina's growth plans may strain its resources and may be subject to high cost pressures in the North American energy sector. Early stage project risks include right-of-way procurement, special interest group opposition, Aboriginal consultation, and environmental and regulatory permitting. Cost escalations may impact project economics. Construction delays due to slow delivery of materials, contractor non-performance, weather conditions and shortages may impact project development. Labour shortages and productivity issues may also affect the successful completion of projects.

Pembina has a centralized and clearly defined governance structure and process for all major projects with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Pembina's emphasis on corporate social responsibility promotes generally positive relationships with landowners, aboriginal groups and governments, which help to facilitate right-of-way acquisition, permitting and scheduling. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors. Compensation programs, communications and the working environment are aligned to attract, develop and retain qualified personnel.

Shipper and Processing Contracts

Throughput on Pembina's pipelines is or will be governed by transportation contracts or tolling arrangements with various producers of petroleum products. In addition, Pembina is party to numerous contracts of varying durations in respect of its gas gathering, processing and fractionating facilities. Any default by counterparties under such contracts or any expirations of such contracts or tolling arrangements without renewal or replacement may have an adverse effect on Pembina's business. Furthermore, some of the contracts associated with its gas gathering, processing and fractionating facilities are comprised of a mixture of firm and interruptible service contracts and the revenue that Pembina earns on the contracts which are based on interruptible service is dependent on the volume of natural gas and NGL produced by producers in the relevant geographic areas and lower than historical production volumes in these areas (for reasons such as low commodity prices) may have an adverse effect on Pembina's revenue.

GENERAL RISK FACTORS

Risk Factors Relating to the Structure of Pembina and its Common Shares

Dilution of Shareholders

Pembina is authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on terms and conditions as established by the Board of Directors without the approval of the shareholders in certain instances. The shareholders will have no pre-emptive rights in connection with such further issues.

Risk Factors Relating to the Activities of Pembina and the Ownership of Common Shares

The following is a list of certain risk factors relating to the activities of Pembina and the ownership its common shares:

the level of Pembina's indebtedness from time to time could impair Pembina's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise;
the uncertainty of future dividend payments by Pembina and the level thereof as Pembina's dividend policy and the funds available for the payment of dividends from time to time will be dependent upon, among other things, operating cash flow generated by Pembina and its subsidiaries, financial requirements for Pembina's operations and the execution of its growth strategy and the satisfaction of solvency tests imposed by the Alberta Business Corporations Act for the declaration and payment of dividends;
Pembina may make future acquisitions or may enter into financings or other transactions involving the issuance of securities of Pembina which may be dilutive; and
the risk that the market value of the common shares may materially deteriorate if Pembina is unable to meet its cash dividend targets or make cash dividends in the future.

Market Value of Common Shares and Other Securities

Pembina cannot predict at what price the common shares, convertible debentures or other securities issued by Pembina will trade in the future. Common shares, convertible debentures and other securities of Pembina will not necessarily trade at values determined solely by reference to the underlying value of Pembina's assets. One of the factors that may influence the market price of such securities is the annual yield on the common shares and the convertible debentures. An increase in market interest rates may lead purchasers of common shares or convertible debentures to demand a higher annual yield and this could adversely affect the market price of the common shares or convertible debentures. In addition, the market price for the common shares and the convertible debentures may be affected by changes in general market conditions, fluctuations in the market for equity or debt securities and numerous other factors beyond the control of Pembina.

Shareholders are encouraged to obtain independent legal, tax and investment advice in their jurisdiction of residence with respect to the holding of common shares.

Regulation

Legislation in Alberta and B.C. exists to ensure that producers have fair and reasonable opportunities to produce, process and market their reserves. In Alberta, the Energy Resources Conservation Board and in B.C., the British Columbia Utilities Commission, may, on application and following a hearing (and in Alberta with the approval of the Lieutenant Governor in Council), declare the operator of a pipeline a common carrier of oil or NGL and, as such, must not discriminate between producers who seek access to the pipeline. Producers and shippers may also apply to the regulatory authorities for a review of tariffs, and such tariffs may then be regulated if it is proven that the tariffs are not just and reasonable. Applications by producers to have a pipeline operator declared a common carrier are usually accompanied by an application to have the tariffs set by the regulatory authorities. The extent to which regulatory authorities in such instances can override existing transportation or processing contracts has not been fully decided. The potential for direct regulation of tolls, other than for the Company's provincially regulated B.C. pipelines, while considered remote by the Company, could result in toll levels that are less advantageous to the Company and could impair the economic operation of such regulated pipeline systems.

Additional Financing and Capital Resources

The timing and amount of Pembina's capital expenditures, and the ability of Pembina to repay or refinance existing debt as it becomes due, directly affects the amount of cash dividends that Pembina pays to shareholders. Future acquisitions, expansions of Pembina's pipeline systems and midstream operations, other capital expenditures, including the capital expenditures that Pembina has committed to in respect of the Resthaven facility, the Saturn facility and the expansion of the Northern NGL System and the repayment or refinancing of existing debt as it becomes due will be financed from sources such as cash generated from operations, the issuance of additional shares or other securities (including debt securities) of Pembina, and borrowings. Dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are made. There can be no assurance that sufficient capital will be available on terms acceptable to Pembina, or at all, to make additional investments, fund future expansions or make other required capital expenditures. To the extent that external sources of capital, including the issuance of additional shares or other securities or the availability of additional credit facilities, become limited or unavailable on favourable terms or at all due to credit market conditions or otherwise, the ability of Pembina to make the necessary capital investments to maintain or expand its operations, to repay outstanding debt and to invest in assets, as the case may be, may be impaired. To the extent Pembina is required to use cash flow to finance capital expenditures or acquisitions or to repay existing debt as it becomes due, the level of dividends to shareholders of Pembina may be reduced.

Counterparty credit risk

Pembina is subject to counterparty credit risk arising out of its operations. A majority of Pembina's accounts receivable are with customers in the oil and gas industry and are subject to normal industry counterparty credit risk. Counterparty credit risk is managed through credit approval and monitoring procedures. The credit worthiness assessment takes into account available qualitative and quantitative information about the counterparty, including, but not limited to, financial status and external credit ratings. Depending on the outcome of each assessment, guarantees or some other credit enhancement may be requested as security. Pembina attempts to mitigate its exposure by entering into contracts with customers that may permit netting or entitle Pembina to lien or take product in-kind and/or allow for termination of the contract on the occurrence of certain events of default. Each business segment monitors outstanding accounts receivable on an ongoing basis. Historically, Pembina has collected its accounts receivable in full.

Debt Service

At the end of 2012, Pembina had exposure to floating interest rates on $525 million in debt. This debt exposure is managed by using derivative financial instruments. A one percent change in short-term interest rates would have an annualized impact of $1.4 million on net cash flows. Variations in interest rates and scheduled principal repayments, if required under the terms of the banking agreements could result in significant changes in the amounts required to be applied to debt service before payment of any dividends to Pembina's shareholders. Certain covenants in the agreements with the lenders may also limit payments by Pembina's operating subsidiaries. Although Pembina believes that the existing credit facilities are sufficient, there can be no assurance that the amount will be adequate for Pembina's financial obligations or that additional funds can be obtained.

Pembina and its subsidiaries are permitted to borrow funds to finance the purchase of pipelines and other energy infrastructure assets, to fund capital expenditures and other financial obligations or expenditures in respect of those assets and for working capital purposes. Amounts paid in respect of interest and principal on debt incurred in respect of those assets reduce the amount of cash flow available for dividends to shareholders. Variations in interest rates and scheduled principal repayments for which Pembina may not be able refinance at favourable rates or at all, could result in significant changes in the amount required to be applied to service debt, which could have detrimental effects on the amount of cash available for dividends to shareholders. Certain covenants contained in the agreements with Pembina's lenders may also limit dividend payments. Although Pembina believes the existing credit facilities are sufficient for immediate requirements, there can be no assurance that the amount will be adequate for the future financial obligations of Pembina or that additional funds will be able to be obtained on terms favourable to Pembina or at all.

The lenders under Pembina's unsecured credit facilities and senior notes have also been provided with similar guarantees and subordination agreements. If Pembina becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, payments to all of the lenders will rank in priority to dividends to shareholders and payments to holders of convertible debentures.

Pembina, on a consolidated basis, is also required to meet certain financial covenants under the credit facilities and the senior notes and is subject to customary restrictions on its operations and activities, including restrictions on the granting of security, incurring indebtedness and the sale of its assets.

Credit Ratings

Rating agencies regularly evaluate Pembina, basing their ratings of its long-term and short-term debt on a number of factors. This includes Pembina's financial strength as well as factors not entirely within its control, including conditions affecting the industry in which Pembina operates generally and the wider state of the economy. There can be no assurance that one or more of Pembina's credit ratings will not be downgraded.

Pembina's borrowing costs and ability to raise funds are directly impacted by its credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions. A credit rating downgrade could potentially impair Pembina's ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit Pembina's access to private and public credit markets and increase the costs of borrowing under its existing credit facilities. A downgrade could also limit Pembina's access to debt markets and increase its cost of borrowing.

The occurrence of a downgrade in Pembina's credit ratings could adversely affect Pembina's ability to execute portions of its business strategy and could have a material adverse effect on its liquidity, results of operations and capital position.

Changes in Legislation

There can be no assurance that income tax laws, regulatory and environmental laws or policies and government incentive programs relating to the pipeline or oil and natural gas industry, will not be changed in a manner which adversely affects Pembina or its shareholders or other securityholders.

Reliance on Management

Shareholders and other securityholders of Pembina will be dependent on senior management and directors of Pembina in respect of the governance, administration and management of all matters relating to Pembina and its operations and administration. The loss of the services of key individuals could have a detrimental effect on Pembina.

Potential Conflicts of Interest

Shareholders are dependent upon senior management of Pembina and the directors of Pembina for the governance, administration and management of Pembina. Additionally, certain directors and officers of Pembina may be directors or officers of entities in competition to Pembina. As such, these directors or officers of Pembina may encounter conflicts of interest in the administration of their duties with respect to Pembina.

Litigation

Pembina and its various subsidiaries and affiliates are, in the course of their business, subject to lawsuits and other claims. Defence and settlement costs associated with such lawsuits and claims can be substantial, even with respect to lawsuits and claims that have no merit. Due to the inherent uncertainty of the litigation process, the resolution of any particular legal proceeding could have a material adverse effect on the financial position or operating results of Pembina.

Variations in Interest Rates and Foreign Exchange Rates

Variations in interest rates could result in a significant change in the amount Pembina pays to service debt, potentially impacting dividends to shareholders. Variations in the exchange rate for the Canadian dollar versus the U.S. dollar could affect future dividends.

Selected Quarterly Operating Information


	2012				2011				2010
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Average volume (mbpd unless stated otherwise)
Conventional Throughput	480.2	443.9	433.9	466.9	422.8	430.4	411.4	390.3	375.0
Oil Sands & Heavy Oil⁽¹⁾	870.0	870.0	870.0	870.0	870.0	775.0	775.0	775.0	775.0
Gas Services Processing (mboe/d)⁽²⁾	46.0	45.8	47.5	44.1	45.3	43.6	40.9	39.4	42.1
NGL sales volume (mboe/d)	115.8	86.7	90.4

⁽¹⁾Oil Sands & Heavy Oil throughput refers to contracted capacity.

⁽²⁾Converted to mboe/d from MMcf/d at a 6:1 ratio.

Selected Quarterly Financial Information


		2012				2011				2010
($ millions, except where noted)		Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Revenue		1,265.7	815.3	870.9	475.5	468.1	300.6	512.4	394.9	290.7
Operations		86.0	69.5	67.7	48.4	55.1	54.4	37.6	44.8	41.9
Cost of goods sold including product purchases		968.6	565.5	641.9	299.1	308.0	145.8	364.3	254.2	161.8
Realized gain (loss) on commodity-related derivative financial instruments		11.0	(2.8)	(12.4)	(0.3)	0.9	3.2	(0.2)	1.4	(0.8)
Operating margin⁽¹⁾		222.1	177.5	148.9	127.7	105.9	103.6	110.3	97.3	86.2
Depreciation and amortization included in operations		47.8	51.6	52.5	21.7	19.6	17.8	15.8	14.8	15.6
Unrealized gain (loss) on commodity-related derivative financial instruments		(2.2)	(23.0)	64.8	(3.5)	0.9	0.7	3.3	0.3	1.8
Gross profit		172.1	102.9	161.2	102.5	87.2	86.5	97.8	82.8	72.4
Adjusted EBITDA⁽¹⁾		199.0	153.8	125.9	111.4	88.2	89.9	103.3	87.2	79.1
Cash flow from operating activities		139.5	130.9	24.1	65.3	73.8	87.7	49.5	74.5	54.6
Cash flow from operating activities per common share ($ per share)		0.48	0.45	0.08	0.39	0.44	0.52	0.30	0.45	0.33
Adjusted cash flow from operating activities⁽¹⁾		172.3	133.2	89.5	98.8	66.0	82.0	81.8	76.0	62.6
Adjusted cash flow from operating activities per common share⁽¹⁾ ($ per share)		0.59	0.46	0.31	0.59	0.39	0.49	0.49	0.45	0.39
Earnings for the period		81.3	30.7	80.4	32.6	45.0	30.1	48.0	42.5	55.2
Earnings per common share ($ per share)
	Basic	0.28	0.11	0.28	0.19	0.27	0.18	0.29	0.25	0.34
	Diluted	0.28	0.11	0.28	0.19	0.27	0.18	0.29	0.25	0.33
Common shares outstanding (millions):
	Weighted average (basic)	291.9	289.2	285.3	168.3	167.4	167.6	167.3	167.0	165.0
	Weighted average (diluted)	292.5	289.7	286.0	168.9	168.2	168.2	168.0	167.6	171.7
	End of period	293.2	290.5	287.8	169.0	167.9	167.7	167.5	167.1	166.9
Dividends declared		118.4	117.3	116.2	65.7	65.4	65.4	65.3	65.1	64.6
Dividends per common share ($ per share)		0.405	0.405	0.405	0.390	0.390	0.390	0.390	0.390	0.390

⁽¹⁾ Refer to "Non-GAAP measures."

During the above periods, Pembina's results were influenced by the following factors and trends:

Increased oil production from customers operating in the Cardium and Deep Basin Cretaceous formations of west central Alberta, which has resulted in increased service offerings in these areas, as well as new connections and capacity expansions;
Increased liquids-rich natural gas production from producers in the WCBS (Deep Basin, Montney, Cardium and emerging Duvernay Shale plays), which has resulted in increased gas gathering and processing at the Company's gas services assets and additional associated NGL transported on its pipelines;
Revenue contribution from the Nipisi and Mitsue Pipelines, which were completed in June and July of 2011; and
The Acquisition of Provident, which closed on April 2, 2012 (for more details please see Note 5 of the Consolidated Financial Statements for the year ended December 31, 2012).

Selected Annual Financial Information


($ millions, except where noted)		2012	2011	2010
Revenue		3,427.4	1,676.0	1,231.8
Earnings		225.0	165.7	175.8
	Per share - basic	0.87	0.99	1.08
	Per share - diluted	0.87	0.99	1.07
Total assets		8,276.5	3,339.2	2,856.8
Long-term financial liabilities⁽¹⁾		3,004.7	1,752.9	1,599.4
Declared dividends per share ($ per share)		1.61	1.56	1.56

⁽¹⁾	Includes loans and borrowings, convertible debentures, long-term derivative financial instrument, provisions and other long-term liabilities.

Additional Information

Additional information about Pembina and legacy Provident filed with Canadian securities commissions and the United States Securities Commission ("SEC"), including quarterly and annual reports, Annual Information Forms (filed with the SEC under Form 40-F), Management Information Circulars and financial statements can be found online at www.sedar.com, www.sec.gov and Pembina's website at www.pembina.com.

Non-GAAP Measures

Throughout this MD&A, Pembina has used the following terms that are not defined by GAAP but are used by Management to evaluate performance of Pembina and its business. Since certain Non-GAAP financial measures may not have a standardized meaning, securities regulations require that Non-GAAP financial measures are clearly defined, qualified and reconciled to their nearest GAAP measure. Concurrent with the Acquisition of Provident, certain Non-GAAP measures definitions have changed from those previously used to better reflect the changes in aspects of Pembina's business activities. Except as otherwise indicated, these Non-GAAP measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Earnings before interest, taxes, depreciation and amortization ("EBITDA")

EBITDA is commonly used by Management, investors and creditors in the calculation of ratios for assessing leverage and financial performance and is calculated as results from operating activities plus share of profit from equity accounted investees (before tax) plus depreciation and amortization (included in operations and general and administrative expense) and unrealized gains or losses on commodity-related derivative financial instruments.

Adjusted EBITDA is EBITDA excluding acquisition-related expenses in connection with the Acquisition.


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except per share amounts)	2012	2011	2012	2011
Results from operating activities	144.3	65.5	416.5	290.7
Share of profit from equity accounted investees (before tax, depreciation and amortization)	2.0	3.2	6.2	12.9
Depreciation and amortization	49.5	20.4	179.4	70.2
Unrealized loss (gain) on commodity-related derivative financial instruments	2.2	(0.9)	(36.1)	(5.2)
EBITDA	198.0	88.2	566.0	368.6
Add:
Acquisition-related expenses	1.0		24.1
Adjusted EBITDA	199.0	88.2	590.1	368.6
EBITDA per common share - basic (dollars)	0.68	0.53	2.19	2.20
Adjusted EBITDA per common share - basic (dollars)	0.68	0.53	2.28	2.20

Adjusted earnings

Adjusted earnings is commonly used by Management for assessing and comparing financial performance each reporting period and is calculated as earnings before tax excluding unrealized gains or losses on derivative financial instruments and acquisition-related expenses in connection with the Acquisition plus share of profit from equity accounted investees (before tax).


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except per share amounts)	2012	2011	2012	2011
Earnings before income tax and equity accounted investees	108.5	43.3	301.3	198.8
Add (deduct):
Unrealized (gains) losses on fair value of derivative financial instruments	6.4	(1.6)	(40.2)	2.4
Share of (loss) profit of investments in equity accounted investees (before tax)	(0.1)	2.0	(1.5)	7.7
Acquisition-related expenses	1.0		24.1
Adjusted earnings	115.8	43.7	283.7	208.9
Adjusted earnings per common share - basic (dollars)	0.40	0.26	1.10	1.25

Adjusted cash flow from operating activities

Adjusted cash flow from operating activities is commonly used by Management for assessing financial performance each reporting period and is calculated as cash flow from operating activities plus the change in non-cash working capital and excluding acquisition-related expenses.


	3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions, except per share amounts)	2012	2011	2012	2011
Cash flow from operating activities	139.5	73.8	359.8	285.5
Add (deduct):
Change in non-cash working capital	31.8	(7.8)	109.9	20.3
Acquisition-related expenses	1.0		24.1
Adjusted cash flow from operating activities	172.3	66.0	493.8	305.8
Adjusted cash flow from operating activities per common share - basic (dollars)	0.59	0.39	1.91	1.83

Operating margin

Operating margin is commonly used by Management for assessing financial performance and is calculated as gross profit before depreciation and amortization included in operations and unrealized gain/loss on commodity-related derivative financial instruments.

Reconciliation of operating margin to gross profit:


		3 Months Ended December 31 (unaudited)		12 Months Ended December 31
($ millions)		2012	2011	2012	2011
Revenue		1,265.7	468.1	3,427.4	1,676.0
Cost of sales:
	Operations	86.0	55.1	271.6	191.9
	Cost of goods sold, including product purchases	968.6	308.0	2,475.0	1,072.3
	Realized gain (loss) on commodity-related derivative financial instruments	11.0	0.9	(4.6)	5.3
Operating margin		222.1	105.9	676.2	417.1
Depreciation and amortization included in operations		47.8	19.6	173.6	68.0
Unrealized gain (loss) on commodity-related derivative financial instruments		(2.2)	0.9	36.1	5.2
Gross profit		172.1	87.2	538.7	354.3

Beginning in the second quarter of 2012, unrealized gain/loss on commodity-related derivative financial instruments has been reclassified from net finance costs to be included in gross profit.

Total enterprise value

Total enterprise value, in combination with other measures, is used by Management and the investment community to assess the overall market value of the business. Total enterprise value is calculated based on the market value of common shares and convertible debentures at a specific date plus senior debt.

Management believes these supplemental Non-GAAP measures facilitate the understanding of Pembina's results from operations, leverage, liquidity and financial positions. Investors should be cautioned that EBITDA, adjusted EBITDA, adjusted earnings, adjusted cash flow from operating activities, operating margin and total enterprise value should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial results determined in accordance with GAAP as an indicator of Pembina's performance. Furthermore, these Non-GAAP measures may not be comparable to similar measures presented by other issuers.

Forward-Looking Statements & Information

In the interest of providing our securityholders and potential investors with information regarding Pembina, including Management's assessment of our future plans and operations, certain statements contained in this MD&A constitute forward-looking statements or information (collectively, "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "could", "believe", "plan", "intend", "design", "target", "undertake", "view", "indicate", "maintain", "explore", "entail", "schedule", "objective", "strategy", "likely", "potential", "envision", "aim", "outlook", "propose", "goal", "would", and similar expressions suggesting future events or future performance.

By their nature, such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Pembina believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of the MD&A.

In particular, this MD&A contains forward-looking statements, including certain financial outlook, pertaining to the following:

the future levels of cash dividends that Pembina intends to pay to its shareholders;
capital expenditure-estimates, plans, schedules, rights and activities and the planning, development, construction, operations and costs of pipelines, gas service facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, including, but not limited to, the Northern NGL System, the Peace HVP expansion between Fox Creed and Fort Saskatchewan, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion, the Phase 2 NGL Expansion, the joint venture full-service terminal in the Judy Creek area of Alberta area, the development program in the Cynthia area west of Drayton Valley, offshore export opportunities for propane, the Nipisi and Mitsue pipelines expansions, the Saturn facility and associated pipelines, the Resthaven facility and associated pipelines, the Nexus expansion, the Redwater expansion;
future expansion of Pembina's pipelines and other infrastructure;
pipeline, processing and storage facility and system operations and throughput levels;
oil and gas industry exploration and development activity levels;
Pembina's strategy and the development of new business initiatives;
growth opportunities;
expectations regarding Pembina's ability to raise capital and to carry out acquisition, expansion and growth plans;
treatment under government regulatory regimes including environmental regulations and related abandonment and reclamation obligations;
future G&A expenses at Pembina
increased throughput potential due to increased activity and new connections and other initiatives on Pembina's pipelines;
future cash flows, potential revenue and cash flow enhancements across Pembina's businesses and the maintenance of operating margins;
tolls and tariffs and transportation, storage and services commitments and contracts;
cash dividends and the tax treatment thereof;
operating risks (including the amount of future liabilities related to pipeline spills and other environmental incidents) and related insurance coverage and inspection and integrity programs;
the expected capacity, incremental volumes and in-services dates of proposed expansions and new developments, including the Northern NGL System, the Peace HVP expansion between Fox Creek and Fort Saskatchewan, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion, the Phase 2 NGL Expansion, the Nipisi and Mitsue pipelines, the Saturn facility, the Resthaven facility and Nexus;
the possibility of offshore export opportunities for propane;
the possibility of renegotiating debt terms, repayment of existing debt, seeking new borrowing and/or issuing equity;
expectations regarding participation in Pembina's DRIP;
the expected impact of changes in share price on annual share-based incentive expense;
inventory and pricing levels in the North American liquids market;
Pembina's discretion to hedge natural gas and NGL volumes; and
competitive conditions.

Various factors or assumptions are typically applied by Pembina in drawing conclusions or making the forecasts, projections, predictions or estimations set out in forward-looking statements based on information currently available to Pembina. These factors and assumptions include, but are not limited to:

the success of Pembina's operations;
prevailing commodity prices and exchange rates and the ability of Pembina to maintain current credit ratings;
the availability of capital to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns;
future operating costs;
geotechnical and integrity costs associated with the Western System;
in respect of the proposed Saturn facility and the Resthaven facility and their estimated in-service dates; that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner, that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of such facilities; that such facilities will be fully supported by long-term firm service agreements accounting for the entire designed throughput at such facilities at the time of such facilities' completion; that there are no unforeseen construction costs related to the facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;
in respect of the expansion of NGL throughput capacity on the Northern NGL System and the crude throughput capacity on the Peace crude system and the estimated in-service dates with respect to the same; that Pembina will receive regulatory approval; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs related to the expansion; and that there are no unforeseen material costs relating to the pipelines that are not recoverable from customers;
in respect of the proposed expansion of Redwater; that Pembina will receive regulatory approval; that Pembina will reach satisfactory long-term arrangements with customers; that counterparties will comply with such contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the proposed fractionators that are not recoverable from customers;
in respect of other developments, expansions and capital expenditures planned, including the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the expectation of additional NGL and crude volumes being transported on the conventional pipelines, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in central Alberta, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven-fee-for-service storage facilities at Redwater and the Redwater fractionator expansion that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the developments, expansions and capital expenditures which are not recoverable from customers;
the future exploration for and production of oil, NGL and natural gas in the capture area around Pembina's conventional and midstream assets, including new production from the Cardium formation in western Alberta, the demand for gathering and processing of hydrocarbons, and the corresponding utilization of Pembina's assets;
in respect of the stability of Pembina's dividend; prevailing commodity prices, margins and exchange rates; that Pembina's future results of operations will be consistent with past performance and management expectations in relation thereto; the continued availability of capital at attractive prices to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns; the success of growth projects; future operating costs; that counterparties to material agreements will continue to perform in a timely manner; that there are no unforeseen events preventing the performance of contracts; and that there are no unforeseen material construction or other costs related to current growth projects or current operations; and
prevailing regulatory, tax and environmental laws and regulations.

The actual results of Pembina could differ materially from those anticipated in these forward-looking statements as a result of the material risk factors set forth below:

the regulatory environment and decisions;
the impact of competitive entities and pricing;
labour and material shortages;
reliance on key alliances and agreements;
the strength and operations of the oil and natural gas production industry and related commodity prices;
non-performance or default by counterparties to agreements which Pembina or one or more of its affiliates has entered into in respect of its business;
actions by governmental or regulatory authorities including changes in tax laws and treatment, changes in royalty rates or increased environmental regulation;
fluctuations in operating results;
adverse general economic and market conditions in Canada, North America and elsewhere, including changes in interest rates, foreign currency exchange rates and commodity prices;
the failure to realize the anticipated benefits of the Acquisition;
the failure to complete remaining integration of the businesses of Pembina and Provident; and
the other factors discussed under "Risk Factors" in Pembina's Annual Information Form ("AIF") for the year ended December 31, 2012. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com and in the U.S. on the Company's profile at www.sec.gov.

These factors should not be construed as exhaustive. Unless required by law, Pembina does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Any forward-looking statements contained herein are expressly qualified by this cautionary statement.

MANAGEMENT'S RESPONSIBILITY

The Consolidated Financial Statements of Pembina Pipeline Corporation (the "Company") are the responsibility of Pembina's management. The financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, using management's best estimates and judgments, where appropriate.

Management is responsible for the reliability and integrity of the financial statements, the notes to the financial statements and other financial information contained in this report. In the preparation of these financial statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependent on future events. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying financial statements.

Management maintains a system of internal controls designed to provide reasonable assurance that assets are safeguarded and that accounting systems provide timely, accurate and reliable financial information.

The Board of Directors of the Company (the "Board") is responsible for ensuring management fulfils its responsibilities for financial reporting and internal control. The Board is assisted in exercising its responsibilities through the Audit Committee, which consists of four non-management directors. The Audit Committee meets periodically with management and the auditors to satisfy itself that management's responsibilities are properly discharged, to review the financial statements and to recommend approval of the financial statements to the Board.

KPMG LLP, the independent auditors, have audited the Company's financial statements in accordance with Canadian generally accepted auditing standards and their report follows. The independent auditors have full and unrestricted access to the Audit Committee to discuss their audit and their related findings.

[signed]			[signed]

Robert B. Michaleski			Peter D. Robertson
Chief Executive Officer			Vice President, Finance & Chief Financial Officer
Pembina Pipeline Corporation			Pembina Pipeline Corporation

March 1, 2013

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Pembina Pipeline Corporation

We have audited the accompanying consolidated financial statements of Pembina Pipeline Corporation, which comprise the consolidated statement of financial position as at December 31, 2012 and December 31, 2011, the consolidated statements of comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Pembina Pipeline Corporation as at December 31, 2012 and December 31, 2011, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

[signed]

KPMG LLP

Calgary, Alberta

March 1, 2013

CONSOLIDATED STATEMENT OF FINANCIAL POSITION


As at December 31 ($ thousands)		Note	2012	2011
Assets Current assets
	Cash and cash equivalents		27,336
	Trade receivables and other	6	331,692	148,267
	Derivative financial instruments	27	7,528	4,643
	Inventory		108,096	21,235
			474,652	174,145
Non-current assets
	Property, plant and equipment	7	5,014,542	2,747,530
	Intangible assets and goodwill	8	2,622,677	243,904
	Investments in equity accounted investees	9	161,205	161,002
	Derivative financial instruments	27	343	1,807
	Other receivables	6	3,080	10,814
			7,801,847	3,165,057
Total Assets			8,276,499	3,339,202
Liabilities and Shareholders' Equity Current liabilities
	Bank indebtedness			676
	Trade payables and accrued liabilities	11	344,740	166,646
	Dividends payable		39,586	21,828
	Loans and borrowings	12	11,652	323,927
	Derivative financial instruments	27	15,932	4,725
			411,910	517,802
Non-current liabilities
	Loans and borrowings	12	1,932,774	1,012,061
	Convertible debentures	13	609,968	289,365
	Derivative financial instruments	27	51,759	12,813
	Employee benefits	25	28,623	16,951
	Share-based payments		17,239	14,060
	Deferred revenue		3,099	2,185
	Provisions	14	361,206	405,433
	Deferred tax liabilities	10	584,489	106,915
			3,589,157	1,859,783
Total Liabilities			4,001,067	2,377,585
Shareholders' Equity
Equity attributable to shareholders of the Company:
	Share capital	15	5,324,058	1,811,734
	Deficit		(1,027,678)	(834,921)
	Accumulated other comprehensive income		(26,123)	(15,196)
			4,270,257	961,617
Non-controlling interest			5,175
Total Equity			4,275,432	961,617
Total Liabilities and Shareholders' Equity			8,276,499	3,339,202

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


Year Ended December 31 ($ thousands, except per share amounts)		Note	2012	2011
Revenue		16	3,427,402	1,676,050
Cost of sales		17	2,920,208	1,332,205
Gain on commodity-related derivative financial instruments		27	31,529	10,471
Gross profit			538,723	354,316

	General and administrative	18	97,488	62,191
	Acquisition-related and other expense		24,748	1,429
			122,236	63,620

Results from operating activities			416,487	290,696

	Finance income		(6,611)	(1,374)
	Finance costs		121,751	93,301
	Net finance costs	21	115,140	91,927

Earnings before income tax and equity accounted investees			301,347	198,769

	Share of loss (profit) of investments in equity accounted investees, net of tax		1,056	(5,766)

	Income tax expense	10	75,339	38,869

Earnings for the year			224,952	165,666

Other comprehensive income (loss)
	Defined benefit plan actuarial losses		(14,568)	(14,159)
	Income tax benefit	10	3,641	3,540
	Other comprehensive loss for the year	25	(10,927)	(10,619)
Total comprehensive income for the year			214,025	155,047
Earnings attributable to:
	Shareholders of the Company		224,844	165,666
	Non-controlling interest		108
			224,952	165,666
Total comprehensive income attributable to:
	Shareholders of the Company		213,917	155,047
	Non-controlling interest		108
			214,025	155,047
Earnings per share attributable to shareholders of the Company:
Basic and diluted earnings per share (dollars)		23	0.87	0.99

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


			Attributable to Shareholders of the Company
($ thousands)		Note	Share Capital	Deficit	Accumulated Other Comprehensive Income	Total	Non-controlling Interest	Total Equity
December 31, 2010			1,794,536	(739,351)	(4,577)	1,050,608		1,050,608
Total comprehensive income for period
	Earnings			165,666		165,666		165,666
Other comprehensive income
	Defined benefit plan actuarial losses, net of tax	25			(10,619)	(10,619)		(10,619)
Total comprehensive income for the year				165,666	(10,619)	155,047		155,047
Transactions with shareholders of the Company
	Share-based payment transactions	15	16,978			16,978		16,978
	Debenture conversions and other	15	220			220		220
	Dividends declared	15		(261,236)		(261,236)		(261,236)
Total transactions with shareholders of the Company			17,198	(261,236)		(244,038)		(244,038)
December 31, 2011			1,811,734	(834,921)	(15,196)	961,617		961,617

Total comprehensive income for period
Earnings				224,844		224,844	108	224,952
Other comprehensive income
Defined benefit plan actuarial losses, net of tax		25			(10,927)	(10,927)		(10,927)
Total comprehensive income (loss) for the year				224,844	(10,927)	213,917	108	214,025
Transactions with shareholders of the Company
Share-based payment transactions		15	9,221			9,221		9,221
Debenture conversions and other		15	432			432		432
Dividends declared		15		(417,601)		(417,601)		(417,601)
Common shares issued on acquisition		5	3,283,976			3,283,976		3,283,976
Dividend reinvestment plan		15	218,695			218,695		218,695
Total transactions with shareholders of the Company			3,512,324	(417,601)		3,094,723		3,094,723
Non-controlling interest assumed on acquisition		5					5,067	5,067
December 31, 2012			5,324,058	(1,027,678)	(26,123)	4,270,257	5,175	4,275,432

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year Ended December 31 ($ thousands)		Note	2012	2011
Cash provided by (used in):
Operating activities:
Earnings for the year			224,952	165,666
Adjustments for:
	Depreciation and amortization	19	179,386	70,219
	Unrealized gain on commodity-related derivative financial instruments		(36,100)	(5,176)
	Net finance costs	21	115,140	91,927
	Share of loss (profit) of investments in equity accounted investees, net of tax		1,056	(5,766)
	Deferred income tax expense	10	75,802	38,869
	Share-based payments expense	26	17,028	18,651
	Employee future benefits expense	25	7,225	4,825
	Other		1,006	989
	Changes in non-cash working capital	24	(109,881)	(20,297)
	Payments from equity accounted investees	9	17,428	16,869
	Decommissioning liability expenditures	14	(4,944)	(3,123)
	Employer future benefit contributions	25	(10,000)	(8,000)
	Net interest paid		(118,291)	(80,115)
Cash flow from operating activities			359,807	285,538
Financing activities:
	Bank borrowings		6,861	153,137
	Repayment of loans and borrowings		(61,332)	(90,596)
	Issuance of debt		450,000	250,000
	Financing fees		(7,343)	(1,774)
	Exercise of stock options		7,295	16,059
	Dividends paid (net of shares issued under the Dividend Reinvestment Plan)	15	(181,148)	(261,102)
Cash flow from financing activities			214,333	65,724
Investing activities:
	Net capital expenditures		(546,820)	(477,335)
	Contributions to equity accounted investees		(8,182)
	Cash acquired on acquisition		8,874
Cash flow used in investing activities			(546,128)	(477,335)
Change in cash			28,012	(126,073)
Cash (bank indebtedness), beginning of year			(676)	125,397
Cash and cash equivalents (bank indebtedness), end of year			27,336	(676)

See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. REPORTING ENTITY

Pembina Pipeline Corporation ("Pembina" or the "Company") is an energy transportation and service provider domiciled in Canada. The consolidated financial statements ("Financial Statements") include the accounts of the Company, its subsidiary companies, partnerships and any interests in associates and jointly controlled entities as at and for the year ended December 31, 2012. These Financial Statements present fairly the financial position, financial performance and cash flows of the Company.

Pembina owns or has interests in pipelines that transport conventional crude oil and natural gas liquids ("NGL"), oil sands and heavy oil pipelines, gas gathering and processing facilities, and an NGL infrastructure and logistics business. Facilities are located in Canada and in the U.S. Pembina also offers midstream services that span across its operations.

2. BASIS OF PREPARATION

a. Statement of compliance

The Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB").

The Financial Statements were authorized for issue by the Board of Directors on March 1, 2013.

b. Basis of measurement

The Financial Statements have been prepared on the historical cost basis except for the following material items in the statement of financial position:

derivative financial instruments are measured at estimated fair value; and
liabilities for cash-settled share-based payment arrangements are measured at estimated fair value.

c. Functional and presentation currency

The Financial Statements are presented in Canadian dollars, which is the Company's functional currency. All financial information presented in Canadian dollars has been disclosed in thousands except where noted.

d. Use of estimates and judgments

The preparation of the Financial Statements in conformity with IFRS requires management to make judgments, estimates and assumptions that are based on the circumstances and estimates at the date of the financial statements and affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.

The following judgment and estimation uncertainties are those management considers material to the Company's financial statements:

Judgments

(i) Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires Management to make judgments about future possible events. The assumptions with respect to determining the fair value of property, plant and equipment and intangible assets acquired generally require the most judgment.

(ii) Componentization

The componentization of the Company's assets are based on management's judgment of what components constitute a significant cost in relation to the total cost of an asset and whether these components have similar or dissimilar patterns of consumption and useful lives for purposes of calculating depreciation and amortization.

(iii) Depreciation and amortization

Estimates

(i) Inventory

(ii) Financial derivative instruments

The Company's financial derivative instruments are recognized on the statement of financial position at fair value based on management's estimate of commodity prices, share price and associated volatility, foreign exchange rates, interest rates and the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors.

(iii) Business Combinations

Estimates of future cash flows, forecast prices, interest rates and discount rates are made in determining the fair value of assets acquired and liabilities assumed for allocation of the purchase price. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities, intangible assets and goodwill in the purchase price analysis. Future net earnings can be affected as a result of changes in future depreciation and amortization, asset or goodwill impairment.

(iv) Defined benefit obligations

The calculation of the defined benefit obligation is sensitive to many estimates, but most significantly of which include the discount rate and long-term rate of return on assets applied.

(v) Provisions and contingencies

Based on the long-term nature of the decommissioning provision, the biggest uncertainties in estimating the provision are the discount rates used, the costs that will be incurred and the timing of when these costs will occur. In addition, in determining the provision it is assumed that the Company will utilize technology and materials that are currently available.

(vi) Share-based payments

Compensation costs pursuant to the share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

(vii) Deferred taxes

The calculation of the deferred tax asset or liability is based on assumptions about the timing of many taxable events and the enacted or substantively enacted rated anticipated to apply to income in the years in which temporary differences are expected to be realized or reversed.

(viii) Depreciation and amortization

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies are set out below have been applied consistently to all periods presented in these Financial Statements.

a. Basis of consolidation

i) Business combinations

The Company measures goodwill as the fair value of the consideration transferred including the recognized amount of any non-controlling interest in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. When the excess is negative, a bargain purchase gain is recognized immediately in profit or loss.

The Company elects on a transaction-by-transaction basis whether to measure non-controlling interest at its fair value, or at its proportionate share of the recognized amount of the identifiable net assets, at the acquisition date.

Non-controlling interests represent equity interests in subsidiaries owned by outside parties. The share of net assets of subsidiaries attributable to non-controlling interests is presented as a separate component of equity. Their share of net income and other comprehensive income is also recognized in this separate component of equity. Changes in the Company's ownership interest in subsidiaries that do not result in a loss of control are accounted for as equity transactions. Adjustments to non-controlling interests are based on a proportionate amount of the net assets of the subsidiary. No adjustments are made to goodwill and no gain or loss is recognized in profit or loss.

Transaction costs, other than those associated with the issue of debt or equity securities, that the Company incurs in connection with a business combination are expensed as incurred.

ii) Subsidiaries

Subsidiaries are entities controlled by the Company. The financial statements of subsidiaries are included in the Financial Statements from the date that control commences until the date that control ceases. The accounting policies of subsidiaries are aligned with the policies adopted by the Company.

iii) Investments in associates and jointly controlled entities (equity accounted investees)

Associates are those entities in which the Company has significant influence, but not control or joint control, over the financial and operating policies. Significant influence is presumed to exist when the Company holds between 20 and 50 percent of the voting power of another entity. Joint ventures are those entities over whose activities the Company has joint control, established by contractual agreement and requiring unanimous consent for strategic financial and operating decisions.

The Financial Statements include the Company's share of the profit or loss and other comprehensive income, after adjustments to align the accounting policies with those of the Company, from the date that significant influence or joint control commences until the date that significant influence or joint control ceases. The Company's investments in its associates and joint ventures are accounted for using the equity method and are recognized initially at cost, including transaction costs.

When the Company's share of losses exceeds its interest in an equity accounted investee, the carrying amount of that interest, including any long-term investments, is reduced to nil, and the recognition of further losses is discontinued except to the extent that the Company has an obligation or has made payments on behalf of the investee.

iv) Jointly controlled operations

A jointly controlled operation is a joint venture carried on by each venture using its own assets in pursuit of the joint operations. The Financial Statements include the assets that the Company controls and the liabilities that it incurs in the course of pursuing the joint operation, and the expenses that the Company incurs and its share of the income that it earns from the joint operation.

v) Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealized revenue and expenses arising from intra-group transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity-accounted investees are eliminated against the investment to the extent of the Company's interest in the investee. Unrealized losses are eliminated in the same way as unrealized gains, but only to the extent that there is no evidence of impairment.

vi) Foreign currency

Transactions in foreign currencies are translated to the Company's functional currency, Canadian dollars, at exchange rates at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies at the reporting date are retranslated to the Company's functional currency at the exchange rate at that date. The foreign currency gain or loss on monetary items is the difference between amortized cost in the functional currency at the beginning of the period, adjusted for effective interest and payments during the period, and the amortized cost in foreign currency translated at the exchange rate at the end of the reporting period.

Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are retranslated to the functional currency at the exchange rate at the date that the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transaction.

Foreign currency differences arising on retranslation are recognized in profit or loss.

b. Inventories

Inventories are measured at the lower of cost and net realizable value and consist primarily of crude oil and NGL. The cost of inventories is determined using the weighted average costing method and includes direct purchase costs and when applicable, costs of production, extraction, fractionation costs, and transportation costs. Net realizable value is the estimated selling price in the ordinary course of business less the estimated selling costs. All changes in the value of the inventories are reflected in inventories and cost of sales.

c. Financial instruments

Financial assets and liabilities are offset and the net amount presented in the statement of financial position when, and only when, the Company has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously.

i) Non-derivative financial assets

The Company initially recognizes loans and receivables and deposits on the date that they are originated. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument.

The Company derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Company is recognized as a separate asset or liability.

The Company classifies non-derivative financial assets into the following categories:

Cash and cash equivalents

Cash and cash equivalents comprise cash balances, call deposits and short-term investments with original maturities of ninety days or less that are subject to an insignificant risk of changes in their fair value, and are used by the Company in the management of its short-term commitments.

Trade and other receivables

Trade and other receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, loans and receivables are measured at amortized cost using the effective interest method less any impairment losses.

ii) Non-derivative financial liabilities

The Company initially recognizes debt securities issued and subordinated liabilities on the date that they are originated. All other financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at which the Company becomes a party to the contractual provisions of the instrument.

The Company derecognizes a financial liability when its contractual obligations are discharged, cancelled or expire.

The Company's non-derivative financial liabilities are comprised of the following: bank indebtedness, trade payables and accrued liabilities, dividends payable, loans and borrowings including finance lease obligations and the liability component of convertible debentures.

Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition these financial liabilities are measured at amortized cost using the effective interest method.

Bank overdrafts that are repayable on demand and form an integral part of the Company's cash management are included as a component of cash and cash equivalents for the purpose of the statement of cash flows.

iii) Share capital

Common shares

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.

iv) Compound financial instruments

The Company's convertible debentures are compound financial instruments consisting of a financial liability and an embedded conversion feature. In accordance with IAS 39, the embedded derivatives are required to be separated from the host contracts and accounted for as stand-alone instruments.

Debentures containing a cash conversion option allow Pembina to pay cash to the converting holder of the debentures, at the option of the Company. As such, the conversion feature is presented as a financial derivative liability within long-term derivative financial instruments. Debentures without a cash conversion option are settled in shares on conversion, and therefore the conversion feature is presented within equity, in accordance with its contractual substance.

On initial recognition and at each reporting date, the embedded conversion feature is measured using a method whereby the fair value is measured using an option pricing model. Subsequent to initial recognition, any unrealized gains or losses arising from fair value changes are recognized through profit or loss in the statement of comprehensive income at each reporting date. If the conversion feature is included in equity, it is not remeasured subsequent to initial recognition. On initial recognition, the debt component, net of issue costs, is recorded as a financial liability and accounted for at amortized cost. Subsequent to initial recognition, the debt component is accreted to the face value of the debentures using the effective interest rate method. Upon conversion, the corresponding portions of the debt and equity are removed from those captions and transferred to share capital.

v) Derivative financial instruments

The Company holds derivative financial instruments to manage its interest rate, commodity, power costs and foreign exchange risk exposures as well as cash conversion features on convertible debentures and a redemption liability. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative meet the definition of a derivative, and the combined instrument is not measured at fair value through profit or loss. Derivatives are recognized initially at fair value with attributable transaction costs recognized in profit or loss as incurred. Subsequent to initial recognition, derivatives are measured at fair value and changes in non-commodity-related derivatives are recognized immediately in profit or loss in net finance costs and changes in commodity-related derivatives are recognized immediately in profit or loss in operating activities.

d. Property, plant and equipment

i) Recognition and measurement

Items of property, plant and equipment are measured at cost less accumulated depreciation and accumulated impairment losses.

Cost includes expenditures that are directly attributable to the acquisition of the asset. The cost of self-constructed assets includes the cost of materials and direct labour, any other costs directly attributable to bringing the assets to a working condition for their intended use, estimated decommissioning provisions and borrowing costs on qualifying assets.

Cost also may include any gain or loss realized on foreign currency transactions directly attributable to the purchase or construction of property, plant and equipment. Purchased software that is integral to the functionality of the related equipment is capitalized as part of that equipment.

When parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate components of property, plant and equipment.

The gain or loss on disposal of an item of property, plant and equipment is determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment, and are recognized within other expense (income) in profit or loss.

ii) Subsequent costs

The cost of replacing a part of an item of property, plant and equipment is recognized in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. The carrying amount of the replaced part is derecognized. The cost of maintenance and repair expenses of the property, plant and equipment are recognized in profit or loss as incurred.

iii) Depreciation

Depreciation is based on the cost of an asset less its residual value. Significant components of individual assets, other than land, are assessed and if a component has a useful life that is different from the remainder of the asset, that component is depreciated separately.

Depreciation is recognized in profit or loss on a straight line or declining balance basis, which most closely reflects the expected pattern of consumption of the future economic benefits embodied in the asset. Pipeline assets and facilities are generally depreciated using the straight line method over 3 to 75 years (an average of 47 years) or declining balance method at rates ranging from 3 percent to 37 percent per annum (an average rate of 15 percent per annum). Facilities and equipment are depreciated using straight line method over 3 to 75 years (at an average rate of 35 years) or declining balance method at rates ranging from 3 to 37 percent (at an average rate of 12 percent per annum). Other assets are depreciated using the straight line method over 2 to 45 years (an average of 17 years) or declining balance method at rates ranging from 3 percent to 37 percent (at an average rate of 2 percent per annum). These rates are established to depreciate remaining net book value over the economic lives or contractual duration of the related assets.

Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term.

Depreciation methods, useful lives and residual values are reviewed annually and adjusted if appropriate.

e. Intangible assets

i) Goodwill

Goodwill that arises upon acquisitions is included in intangible assets. See note 3(a)(i) for the policy on measurement of goodwill at initial recognition.

Subsequent measurement

Goodwill is measured at cost less accumulated impairment losses.

In respect of equity accounted investees, the carrying amount of goodwill is included in the carrying amount of the investment, and an impairment loss on such an investment is allocated to the investment and not to any asset, including goodwill, that forms the carrying amount of the equity accounted investee.

ii) Other intangible assets

Other intangible assets acquired individually by the Company and have finite useful lives are recognized and measured at cost less accumulated amortization and accumulated impairment losses.

iii) Subsequent expenditures

Subsequent expenditures are capitalized only when it increases the future economic benefits embodied in the specific asset to which it relates. All other expenditures are recognized in profit or loss as incurred.

iv) Amortization

Amortization is based on the cost of an asset less its residual value.

Amortization is recognized in profit or loss on a straight-line basis over the estimated useful lives of intangible assets, other than goodwill, from the date that they are available for use. The estimated useful lives of other intangible assets with finite useful lives range from 3 to 25 years (at an average of 17 years).

Amortization methods, useful lives and residual values are reviewed annually and adjusted if appropriate.

f. Leased assets

Leases which the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. The leased asset is initially recognized at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset.

Other leases are operating leases and are not recognized in the Company's statement of financial position.

g. Lease payments

Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.

Minimum lease payments made under finance leases are apportioned between the finance cost and the reduction of the outstanding liability. The finance cost is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability. Contingent lease payments are accounted for by revising the minimum lease payments over the remaining life.

i) Determining whether an arrangement contains a lease

At inception of an arrangement, the Company determines whether such an arrangement is or contains a lease. A specific asset is the subject of a lease if fulfilment of the arrangement is dependent on the use of that specified asset. An arrangement conveys the right to use the asset if the arrangement conveys to a lessee the right to control the use of the underlying asset.

At inception or upon reassessment of the arrangement, the Company separates payments and other consideration required by such an arrangement into those for the lease and those for other elements on the basis of their relative fair values. If the Company concludes for a finance lease that it is impracticable to separate the payments reliably, an asset and liability are recognized at an amount equal to the fair value of the underlying asset. Subsequently, the liability is reduced as payments are made and an imputed finance cost on the liability is recognized using the Company's incremental borrowing rate.

h. Impairment

i) Non-derivative financial assets

A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is objective evidence that it is impaired. A financial asset is impaired if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset, and that a loss event had a negative effect on the estimated future cash flows of that asset and the impact can be estimated reliably.

Objective evidence that financial assets are impaired can include default or delinquency by a debtor, restructuring of an amount due to the Company on terms that the Company would not consider otherwise, indications that a debtor or issuer will enter bankruptcy, adverse changes in the payment status of borrowers or issuers in the Company, economic conditions that correlate with defaults or the disappearance of an active market for a security or a significant or prolonged decline in the fair value below cost.

Trade and other receivables ("Receivables")

The Company considers evidence of impairment for Receivables at both a specific asset and collective level. All individually significant Receivables are assessed for specific impairment. All individually significant Receivables found not to be specifically impaired are then collectively assessed for any impairment that has been incurred but not yet identified. Receivables that are not individually significant are collectively assessed for impairment by grouping together Receivables with similar risk characteristics.

In assessing collective impairment, the Company uses historical trends of the probability of default, timing of recoveries and the amount of loss incurred, adjusted for management's judgment as to whether current economic and credit conditions are such that the actual losses are likely to be greater or less than suggested by historical trends.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the asset's original effective interest rate. Losses are recognized in profit or loss and reflected in an allowance account against Receivables. Interest on the impaired asset continues to be recognized through the unwinding of the discount. When a subsequent event causes the amount of impairment loss to decrease, the decrease in impairment loss is reversed through profit or loss.

ii) Non-financial assets

The carrying amounts of the Company's non-financial assets, other than line fill and assets arising from employee benefits and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated.

For goodwill and intangible assets that have indefinite useful lives or that are not yet available for use, the recoverable amount is estimated each year at the same time. An impairment loss is recognized if the carrying amount of an asset or its related Cash Generating Unit ("CGU") exceeds its estimated recoverable amount.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU. For the purpose of impairment testing, assets that cannot be tested individually are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or CGUs. Subject to an operating segment ceiling test, for the purpose of goodwill impairment testing, CGUs to which goodwill has been allocated are aggregated so that the level at which impairment testing is performed reflects the lowest level at which goodwill is monitored for internal purposes. Goodwill acquired in a business combination is allocated to CGUs or groups of CGUs that are expected to benefit from the synergies of the combination.

The Company's corporate assets do not generate separate cash inflows and are utilized by more than one CGU. Corporate assets are allocated to CGUs on a reasonable and consistent basis and tested for impairment as part of the testing of the CGU to which the corporate asset is allocated. If there is an indication that a corporate asset may be impaired, then the recoverable amount is determined for the CGU to which the corporate asset belongs.

Impairment losses are recognized in profit or loss. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGU (group of CGUs), and then to reduce the carrying amounts of the other assets in the CGU (group of CGUs) on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized.

Goodwill that forms part of the carrying amount of an investment in an associate is not recognized separately, and therefore is not tested for impairment separately. Instead, the entire amount of the investment in an associate is tested for impairment as a single asset when there is objective evidence that the investment in an associate may be impaired.

i. Employee benefits

i) Defined contribution plans

A defined contribution plan is a post-employment benefit plan under which an entity pays fixed contributions into a separate entity and will have no legal or constructive obligation to pay further amounts. Obligations for contributions to defined contribution pension plans are recognized as an employee benefit expense in profit or loss in the periods during which services are rendered by employees. Prepaid contributions are recognized as an asset to the extent that a cash refund or a reduction in future payments is available. Contributions to a defined contribution plan that are due more than 12 months after the end of the period in which the employees render the service are discounted to their present value.

ii) Defined benefit pension plans

A defined benefit pension plan is a post-employment benefit plan other than a defined contribution plan. The Company's net obligation in respect of Defined Benefit Pension Plans ("Plans") is calculated separately for each plan by estimating the amount of future benefit that employees have earned in return for their service in the current and prior periods, discounted to determine its present value. Unrecognized past service costs and the fair value of any plan assets are deducted. The discount rate used to determine the present value is comprised of the following: estimated returns for each major asset class consistent with market conditions on the valuation date and the target asset mix specified in the Plans investment policy, additional net returns assumed to be achievable due to active equity management, implicit provision for expenses determined as the average rate of investment and administrative expenses paid by the Plans over the last five years, and a margin for adverse deviations, based on the proportion of the Plans' assets invested in equities in excess of the return expected on equities, over government bond yields.

The calculation is performed, at a minimum, every three years by a qualified actuary using the actuarial cost method. When the calculation results in a benefit to the Company, the recognized asset is limited to the total of any unrecognized past service costs and the present value of economic benefits available in the form of any future refunds from the plan or reductions in future contributions to the plan. In order to calculate the present value of economic benefits, consideration is given to any minimum funding requirements that apply to any plan in the Company. An economic benefit is available to the Company if it is realizable during the life of the plan or on settlement of the plan liabilities.

When the benefits of a plan are improved, the portion of the increased benefit relating to past service by employees is recognized in profit or loss on a straight-line basis over the average period until the benefits become vested. To the extent that the benefits vest immediately, the expense is recognized immediately in profit or loss.

The Company recognizes all actuarial gains and losses arising from defined benefit plans in other comprehensive income and expenses related to defined benefit plans in personnel expenses in profit or loss.

The Company recognizes gains or losses on the curtailment or settlement of a defined benefit plan when the curtailment or settlement occurs. The gain or loss on curtailment comprises any resulting change in the fair value of plan assets, change in the present value of defined benefit obligation and any related actuarial gains or losses and past service cost that had not previously been recognized.

iii) Other long-term employee benefits

The Company's net obligation in respect of long-term employee benefits other than pension plans is the amount of future benefit that employees have earned in return for their service in the current and prior periods is discounted to determine its present value, and the fair value of any related assets is deducted. The discount rate is comprised of the following: estimated returns for each major asset class consistent with market conditions on the valuation date and the target asset mix specified in the Plans investment policy, additional net returns assumed to be achievable due to active equity management, implicit provision for expenses determined as the average rate of investment and administrative expenses paid from the Plans over the last five years, and a margin for adverse deviations, based on the proportion of the Plans assets invested in equities in excess return expected on equities, over government yield bonds.

The calculation is performed using an actuary.

iv) Short-term employee benefits

Short-term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is provided.

A liability is recognized for the amount expected to be paid under short-term cash bonus if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be estimated reliably.

v) Share-based payment transactions

For equity settled share-based payment plans, the fair value of the share-based payment at grant date is recognized as an expense, with a corresponding increase in equity, over the period that the employees unconditionally become entitled to the awards. The amount recognized as an expense is adjusted to reflect the number of awards for which the related service and non-market vesting conditions are expected to be met, such that the amount ultimately recognized as an expense is based on the number of awards that meet the related service conditions at the vesting date.

For cash settled share-based payment plans, the fair value of the amount payable to employees is recognized as an expense with a corresponding increase in liabilities, over the period that the employees unconditionally become entitled to payment. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized as an expense in profit or loss.

j. Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are remeasured at each reporting date based on the best estimate of the settlement amount. The unwinding of the discount rate (accretion) is recognized as a finance cost.

Decommissioning obligation

The Company's activities give rise to dismantling, decommissioning and site disturbance remediation activities. A provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value, based on a risk free rate, of management's best estimate of expenditure required to settle the obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time, changes in the risk free rate and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows or risk free rate are added to or deducted from the cost of the related asset.

k. Revenue

Revenue in the course of ordinary activities is measured at the fair value of the consideration received or receivable. Revenue is recognized when persuasive evidence exists that the significant risks and rewards of ownership have been transferred to the customer or the service has been provided, recovery of the consideration is probable, the associated costs can be estimated reliably, there is no continuing management involvement with the goods, and the amount of revenue can be measured reliably.

The timing of the transfer of significant risks and rewards varies depending on the individual terms of the sales or service agreement. For product sales, usually transfer of significant risks and rewards occurs when the product is delivered to a customer. For pipeline transportation revenues and storage revenue, transfer of significant risks and rewards usually occurs when the service is provided as per the contract with the customer. For rate or contractually regulated pipeline operations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by agreement or regulatory authority.

Certain commodity buy/sell arrangements where the risks and rewards of ownership have not transferred are recognized on a net basis in profit or loss.

l. Finance income and finance costs

Finance income comprises interest income on funds deposited and invested, gains on non-commodity-related derivatives measured at fair value through profit or loss and foreign exchange gains. Interest income is recognized as it accrues in profit or loss, using the effective interest method.

Finance costs comprise interest expense on loans and borrowings, unwinding of discount rate on provisions, losses on disposal of available for sale financial assets, losses on non-commodity-related derivatives, impairment losses recognized on financial assets (other than trade and other receivables) and foreign exchange losses.

Borrowing costs that are not directly attributable to the acquisition, or construction of a qualifying asset are recognized in profit or loss using the effective interest method.

m. Income tax

Income tax expense comprises current and deferred tax. Current and deferred tax are recognized in profit or loss except to the extent that it relates to a business combination, or items are recognized directly in equity or in other comprehensive income.

Current tax is the expected tax payable or receivable on the taxable income or loss for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized for:

temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss;
temporary differences relating to investments in subsidiaries and jointly controlled entities to the extent that it is probable that they will not reverse in the foreseeable future; and
taxable temporary differences arising on the initial recognition of goodwill.

The measurement of deferred tax reflects the tax consequences that would follow the manner in which the Company expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date.

Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

In determining the amount of current and deferred tax, the Company takes into account the impact of uncertain tax positions and whether additional taxes and interest may be due. This assessment relies on estimates and assumptions and may involve a series of judgments about future events. New information may become available that causes the Company to change its judgment regarding the adequacy of existing tax liabilities, such changes to tax liabilities will impact tax expense in the period that such a determination is made.

n. Earnings per share

The Company presents basic and diluted earnings per share ("EPS") data for its common shares. Basic EPS is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted EPS is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding, for the effects of all potentially dilutive common shares, which comprise convertible debentures and share options granted to employees ("Convertible Instruments"). Only outstanding and Convertible Instruments that will have a dilutive effect are included in fully diluted calculations.

The dilutive effect of Convertible Instruments is determined whereby outstanding Convertible Instruments at the end of the period are assumed to have been converted at the beginning of the period or at the time issued if issued during the year. Amounts charged to income or loss relating to the outstanding Convertible Instruments are added back to net income for the diluted calculations. The shares issued upon conversion are included in the denominator of per share basic calculations for the date of issue.

o. Segment reporting

An operating segment is a component of the Company that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Company's other components. All operating segments' operating results are reviewed regularly by the Company's Chief Executive Officer ("CEO"), Chief Financial Officer ("CFO") and Chief Operating Officer ("COO") to make decisions about resources to be allocated to the segment and assess its performance, and for which discrete financial information is available.

Segment results that are reported to the CEO, CFO and COO include items directly attributable to a segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly corporate assets, head office expenses, finance income and costs and income tax assets and liabilities.

Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and intangible assets other than goodwill.

p. Cash flow statements

The cash flow statement is prepared using the indirect method. Changes in balance sheet items that have not resulted in cash flows such as share-based payment expense, unrealized gains and losses, depreciation and amortization, employee future benefit expenses, deferred income tax expense, share of profit from equity accounted investees, among others, have been eliminated for the purpose of preparing this statement. Dividends paid to ordinary shareholders, among other expenditures, are included in financing activities. Interest paid is included in operating activities.

q. New standards and interpretations not yet adopted

Amendments to IFRS 7 Financial Instruments: Disclosures are effective for annual periods beginning on or after January 1, 2013. The adoption of these amendments is not expected to have a material impact on the Company's Financial Statements.

IFRS 9 (2010) Financial Instruments is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted. The Company intends to adopt IFRS 9 (2010) in its financial statements for the annual period beginning January 1, 2015. The extent of the impact of adoption of IFRS 9 (2010) has not yet been determined.

IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interest in Other Entities and IFRS 13 Fair Value Measurement are effective for annual periods beginning on or after January 1, 2013. The adoption of these standards is not expected to have a material impact on the Company's financial statements.

Amendments to IAS 19 Employee Future Benefits are effective for annual periods beginning on or after January 1, 2013. The adoption of these amendments is not expected to have a material impact on the Company's Financial Statements.

IAS 32 Financial Instruments: Presentation is effective for annual periods beginning on or after January 1, 2014. The Company is currently evaluating the impact that the standard will have on its results of operations and financial position.

4. DETERMINATION OF FAIR VALUES

A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

i) Property, plant and equipment

The fair value of property, plant and equipment recognized as a result of a business combination is based on market values when available and depreciated replacement cost when appropriate. Depreciated replacement cost reflects adjustments for physical deterioration as well as functional and economic obsolescence.

ii) Intangible assets

The fair value of intangible assets acquired in a business combination is determined using the multi-period excess earnings method, whereby the subject asset is valued after deducting a fair return on all other assets that are part of creating the related cash flows.

The fair value of other intangible assets is based on the discounted cash flows expected to be derived from the use and eventual sale of the assets.

iii) Derivatives

Fair value of derivatives, with the exception of the redemption liability which is related to the acquisition of the Company's subsidiary, are estimated by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, quoted market prices per share and volatility rates at the period ends.

The redemption liability related to one of the Company's subsidiaries represents a put option, held by the non-controlling interest, to sell the remaining one-third of the business to the Company after the third anniversary of the acquisition date (October 3, 2014). The put price to be paid by the Company for the residual interest upon exercise is based on a multiple of the subsidiary's earnings during the three year period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates (see Note 27 "Financial Instruments and Financial Risk Management").

Fair values reflect the credit risk of the instrument and include adjustments to take account of the credit risk of the Company entity and counterparty when appropriate.

iv) Non-derivative financial assets and liabilities

Fair value, which is determined for disclosure purposes, is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date. In respect of the convertible debentures, the fair value is determined by the market price of the convertible debenture on the reporting date. For finance leases the market rate of interest is determined by reference to similar lease agreements.

v) Share-based payment transactions

The fair value of the employee share options is measured using the Black-Scholes formula. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends, expected forfeitures and the risk-free interest rate (based on government bonds). Service and non-market performance conditions attached to the transactions are not taken into account in determining fair value.

The fair value of the long-term share unit award incentive plan and associated distribution units are measured based on the reporting date market price of the Company's shares. Expected dividends are not taken into account in determining fair value as they are issued as additional distribution share units.

vi) Inventories

The net realizable value of inventories is determined based on the estimated selling price in the ordinary course of business less estimated cost to sell.

5. ACQUISITION

On April 2, 2012, Pembina acquired all of the outstanding Provident Energy Ltd. ("Provident") common shares (the "Provident Shares") in exchange for Pembina common shares valued at approximately $3.3 billion (the "Acquisition"). Provident shareholders received 0.425 of a Pembina common share for each Provident Share held for a total of 116,535,750 Pembina common shares. On closing, Pembina assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2017, and the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2018 (collectively, the "Provident Debentures"). The face value of the outstanding Provident Debentures at April 2, 2012 was $345 million. The debentures remain outstanding and continue with terms and maturity as originally set out in their respective indentures. Pursuant to the Acquisition, Provident amalgamated with a wholly-owned subsidiary of Pembina and has continued under the name "Pembina NGL Corporation". The results of the acquired business are included as part of the Midstream business.

The purchase price equation, subject to finalization of deferred tax liabilities, is based on assessed fair values and is estimated as follows:


($ millions)
Cash					9
Trade receivables and other					195
Inventory					87
Property, plant and equipment					1,988
Intangible assets and goodwill (including $1,753 goodwill)					2,414
Trade payables and accrued liabilities					(249)
Derivative financial instruments - current					(53)
Derivative financial instruments - non-current					(36)
Loans and borrowings					(215)
Convertible debentures					(317)
Provisions and other					(128)
Deferred tax liabilities					(406)
Non-controlling interest					(5)
					3,284

The determination of fair values and the purchase price equation are based upon an independent valuation. The primary drivers that generate goodwill are synergies and business opportunities from the integration of Pembina and Provident and the acquisition of a talented workforce. The recognized goodwill is generally not expected to be deductible for tax purposes.

Upon closing of the Acquisition, Pembina repaid Provident's revolving term credit facility of $205 million.

The Company has recognized $24.1 million in acquisition-related expenses. These expenses are included in acquisition-related and other expenses in the Financial Statements.

The Pembina Shares were listed and began trading on the NYSE under the symbol "PBA" on April 2, 2012.

Revenue generated by the Provident business for the period from the Acquisition date of April 2, 2012 to December 31, 2012, before intersegment eliminations, was $1,151.4 million. Net earnings, before intersegment eliminations, for the same period were $54.2 million.

Unaudited proforma consolidated revenue (prepared as if the Provident Acquisition had occurred on January 1, 2012) for the year ended December 31, 2012 are $3,967.5 million and net earnings for the same period are $277 million.

6. TRADE AND OTHER RECEIVABLES


December 31 ($ thousands)	2012	2011
Trade accounts receivable from customers	310,364	116,809
Trade accounts receivable and other receivables from related parties	10,814	28,864
Prepayments	10,514	2,594
Total current trade and other receivables	331,692	148,267
Non-current holdbacks receivable	3,080
Receivable due from related parties		10,814
	334,772	159,081

On March 29, 2012 the Musreau Deep Cut experienced a gear box failure, resulting in an interruption to business until Pembina brought the Deep Cut compressor back into service on September 2, 2012. Business interruption and capital insurance claims are currently being pursued. Pembina has recognized a receivable based on information on the claim status as of the reporting date.

7. PROPERTY, PLANT AND EQUIPMENT


($ thousands)	Land and Land Rights	Pipelines	Facilities and Equipment	Linefill and Other	Assets Under Construction	Total
Cost
Balance at December 31, 2010	57,248	1,997,267	483,765	149,117	260,819	2,948,216
Additions	10,006	216,293	30,208	48,891	222,196	527,594
Change in decommissioning provision		117,491				117,491
Capitalized interest		207			10,015	10,222
Transfers	104	169,354	15,075	1,139	(185,672)
Disposals and other	(139)	(585)	(428)	1,579		427
Balance at December 31, 2011	67,219	2,500,027	528,620	200,726⁽¹⁾	307,358	3,603,950⁽¹⁾
Acquisition (Note 5)	18,093	276,225	1,319,286	287,319	87,273	1,988,196
Additions	5,900	20,315	38,533	31,021	488,545	584,314
Change in decommissioning provision		(139,468)	(31,441)			(170,909)
Capitalized interest		570	98		13,821	14,489
Transfers	1,793	(61,401)	217,928	(13,149)	(145,171)
Disposals and other	(5,001)	(2,534)	(828)	626		(7,737)
Balance at December 31, 2012	88,004	2,593,734	2,072,196	506,543	751,826	6,012,303

Depreciation
Balance at December 31, 2010	4,043	659,277	76,498	49,301		789,119
Depreciation	45	48,334	16,768	4,374		69,521
Disposals		(516)	(268)	(1,436)		(2,220)
Balance at December 31, 2011	4,088	707,095	92,998	52,239		856,420
Depreciation	279	70,795	54,476	19,629		145,179
Transfers		917	24,628	(25,545)
Disposals and other		(2,099)	(225)	(1,514)		(3,838)
Balance at December 31, 2012	4,367	776,708	171,877	44,809		997,761

Carrying amounts
December 31, 2011	63,131	1,792,932	435,622	148,487	307,358	2,747,530
December 31, 2012	83,637	1,817,026	1,900,319	461,734	751,826	5,014,542

⁽¹⁾$1.5 million was reclassified from inventory to Linefill and Other at December 31, 2011.

Property, plant and equipment under construction

Costs of assets under construction at December 31, 2012 totalled $751.8 million ($2011: $307.4 million). Such amounts include capitalized borrowing costs.

For the year ended December 31, 2012, capitalized borrowing costs related to the construction of the new pipelines or facilities amounted to $14.5 million (2011: $10.2 million), with capitalization rates ranging from 4.29 percent to 4.77 percent (2011: 4.91 percent to 5.36 percent).

Commitments

At December 31, 2012, the Company has contractual commitments for the acquisition and or construction of property, plant and equipment of $362.8 million (December 31, 2011: $364.3 million).

8. INTANGIBLE ASSETS AND GOODWILL


		Other Intangible Assets
	Goodwill	Purchase and Sale Contracts	Customer Relationships	Purchase Options	Total Other Intangible Assets	Total Goodwill & Intangible Assets
Cost
Balance at December 31, 2010 and 2011	222,670	23,038			23,038	245,708
Acquisition (Note 5)	1,752,942	157,051	226,497	277,350	660,898	2,413,840
Additions and other		5,000			5,000	5,000
Balance at December 31, 2012	1,975,612	185,089	226,497	277,350	688,936	2,664,548

Amortization
Accumulated amortization at December 31, 2010		1,106			1,106	1,106
Amortization		698			698	698
Accumulated amortization at December 31, 2011		1,804			1,804	1,804
Amortization		24,778	15,289		40,067	40,067
Accumulated amortization at December 31, 2012		26,582	15,289		41,871	41,871

Carrying amounts
December 31, 2011	222,670	21,234			21,234	243,904
December 31, 2012	1,975,612	158,507	211,208	277,350	647,065	2,622,677

Other intangible assets consist of customer purchase and sale contracts with several producers acquired through business combinations. In addition, Pembina has a purchase option of $277.3 million to acquire property, plant and equipment. The purchase option is not being amortized because it is not exercisable until 2018.

The aggregate carrying amount of intangible assets and goodwill allocated to each operating segment is as follows:


($ thousands)	2012	2011
Conventional Pipelines	315,470	194,370
Oil Sands and Heavy Oil	33,300	28,300
Gas Services	196,136	21,234
Midstream	2,077,771
	2,622,677	243,904

Impairment testing

For the purpose of impairment testing, goodwill is allocated to the Company's operating divisions which represent the lowest level within the Company at which the goodwill is monitored for internal management purposes, which is not higher than the Company's operating segments. Impairment testing for goodwill was performed on December 31, 2012. The recoverable amounts were based on their value in use and were determined to be higher than their carrying amounts.

Value in use was determined by discounting the future cash flows generated from the continuing use of each cash generating unit. The calculation of the value in use was based on the following key assumptions:

Cash flows were projected based on past experience, actual operating results and the first 5 years of the business plan approved by management. Cash flows for periods up to 68 years (2011: 75 years) were extrapolated using a constant growth rate of 2 percent (2011: 1.9 percent), which does not exceed the long-term average growth rate for the industry. Pre-tax discount rates between 7.49 percent and 8.63 percent (2011: 7.51 percent and 8.84 percent) were applied in determining the recoverable amount of the cash generating units. The discount rates were estimated based on past experience, the Company's risk free rate and average cost of debt in addition to estimates of the specific cash generating unit's equity risk premium, size premium, small capitalization premium, projection risk, betas, tax rate and industry targeted debt to equity ratios.

9. INVESTMENTS IN EQUITY ACCOUNTED INVESTEES

The Company has a 50 percent interest in two jointly controlled, equity accounted investees that are reported using the equity method of accounting. The carrying value of the investment at December 31, 2012 is $161.2 million (2011: $161 million).


	Pembina's Proportionate Share of Balance As At				Pembina's Proportionate Share of Transaction Value For The Year Ended			Payments from Equity Accounted Investees
	Current Assets	Non-Current Assets	Current Liabilities	Non-Current Liabilities	Revenues	Expenses	Profit and Loss
($ thousands)
Fort Saskatchewan Ethylene Storage Corporation (FSESC)	316	11	1		78	2	76
Fort Saskatchewan Ethylene Storage Limited Partnership (FSESLP)	3,271	26,216	20,125	12,087	45,925	7,082	38,843	16,869
December 31, 2011	3,587	26,227	20,126	12,087	46,003	7,084	38,919	16,869
FSESC	331	4	2		12	4	8
FSESLP	2,917	41,343	16,950	21,457	14,646	8,788	5,858	17,428
December 31, 2012	3,248	41,347	16,952	21,457	14,658	8,792	5,866	17,428

On acquisition, Pembina recognized a fair value adjustment which is amortized over the useful life of the assets. Pembina's share of profit of investments in equity accounted investees includes amortization of the fair value adjustment of $7.7 million (2011: $5.2 million), derecognition of fair value adjustment of $nil (2011: $25.2 million), income tax benefit (expense) of $0.5 million (2011: $(1.9) million) and other $0.3 million (2011: $(0.7) million) In 2012, Pembina made contributions for the construction of caverns of $8.2 million (2011: $nil).

Commitments

At December 31, 2012, the Company's share of investment in equity accounted investees contractual commitments for the construction of property, plant and equipment is $31.6 million (December 31, 2011: $42.7 million).

10. INCOME TAXES

The components of the deferred assets and deferred tax liabilities are as follows:


($ thousands)	2012	2011
Asset:
Intangible assets		2,512
Derivative financial instruments	22,787	2,772
Employee benefits	7,156	4,238
Share-based payments	7,971	3,515
Provisions	114,617	101,358
Benefit of loss carryforwards	76,702	62,426
Other deductible temporary differences	2,783	4,240
Total deferred tax asset	232,016	181,061

Liability:
Property, plant and equipment	589,909	203,178
Intangible assets	127,467
Investments in equity accounted investees	21,841	25,802
Taxable limited partnership income deferral	75,295	50,175
Other taxable temporary differences	1,993	8,821
Total deferred tax liability	816,505	287,976
Total deferred tax liability	584,489	106,915

The Company's consolidated effective tax rate for the year ended December 31, 2012 was 25 percent (2011: 19.6 percent).

Reconciliation of effective tax rate


Year Ended December 31 ($ thousands)	2012	2011
Earnings before income tax	301,347	198,769

Statutory tax rate	25.0%	26.5%

Income tax at statutory rate	75,337	52,674

Tax rate changes on deferred income tax balances	1,948	(5,051)
Changes in estimate from prior year	(2,160)	(8,880)
Other	214	126
Income tax expense	75,339	38,869

In 2007, the Canadian federal government enacted a change in the federal income tax rate from 16.5 percent in 2011 to 15 percent in 2012.

Income tax expense


Year Ended December 31 ($ thousands)		2012	2011
Current tax benefit
	Adjustment for prior period	(463)
	Total current tax benefit	(463)
Deferred tax expense
	Origination and reversal of temporary differences	58,005	23,826
	Tax rate changes on deferred tax balances	1,948	(5,075)
	Decrease in tax loss carry forward	15,849	20,118
	Total deferred tax expense	75,802	38,869
Total income tax expense		75,339	38,869

The movement of the deferred tax liability is as follows:
($ thousands)		2012	2011
Opening balance, January 1		106,915	69,686
Deferred income tax expense		75,802	38,869
Tax benefit on share of (loss) profit of equity accounted investees		(458)	1,900
Income tax benefit in other comprehensive income		(3,641)	(3,540)
Acquisition (Note 5)		405,847
Other		24
Deferred income taxes, December 31		584,489	106,915

11. TRADE PAYABLES AND ACCRUED LIABILITIES


December 31 ($ thousands)	2012	2011
Trade payables	301,936	141,452
Non-trade payables & accrued liabilities⁽¹⁾	42,804	25,194
	344,740	166,646

⁽¹⁾Includes current portion of decommissioning provision of $532 (2011 - $10,720).

U.S. dollar trade payables at December 31, 2012 are $0.3 million (December 31, 2011: Nil).

12. LOANS AND BORROWINGS

This note provides information about the contractual terms of the Company's interest-bearing loans and borrowings, which are measured at amortized cost.

Carrying value terms and debt repayment schedule

Terms and conditions of outstanding loans were as follows:


($ thousands)				Carrying amount⁽³⁾
	Available facilities at December 31, 2012	Nominal interest rate	Year of maturity	December 31, 2012	December 31, 2011
Operating facility⁽¹⁾	30,000	prime + 0.50 or BA⁽²⁾+ 1.50	2013		3,139
Revolving unsecured credit facility	1,500,000	prime + 0.50 or BA⁽²⁾ + 1.50	2017	520,676	309,981
Senior secured notes		7.38			57,499
Senior unsecured notes - Series A	175,000	5.99	2014	174,677	174,462
Senior unsecured notes - Series C	200,000	5.58	2021	196,983	196,638
Senior unsecured notes - Series D	267,000	5.91	2019	265,604	265,403
Senior unsecured term facility	75,000	6.16	2014	74,800	74,658
Senior unsecured medium-term notes 1	250,000	4.89	2021	248,714	248,558
Senior unsecured medium-term notes 2	450,000	3.77	2022	447,825
Subsidiary debt	9,347	5.04	2014	9,347
Finance lease liabilities				5,800	5,650
Total interest bearing liabilities	2,956,347			1,944,426	1,335,988
Less current portion				(11,652)	(323,927)
Total non-current				1,932,774	1,012,061

⁽¹⁾		Operating facility expected to be renewed on an annual basis.
⁽²⁾		Bankers' Acceptance.
⁽³⁾		Deferred financing fees are all classified as non-current. Non-current carrying amount of facilities are net of deferred financing fees.

All facilities are governed by specific debt covenants which Pembina has been in compliance with during the years ended December 31, 2012 and 2011.

For more information about the Company's exposure to interest rate, foreign currency and liquidity risk, see financial instruments and financial risk management Note 27.

13. CONVERTIBLE DEBENTURES


($ thousands, except as noted)	Series C - 5.75%	Series E - 5.75%	Series F - 5.75%	Total
Conversion price (dollars)	$28.55	$24.94	$29.53
Interest payable semi-annually in arrears on:	May 31 and November 30	June 30 and December 31	June 30 and December 31
Maturity date	November 30, 2020	December 31, 2017	December 31, 2018
Balance December 31, 2010	288,635			288,635
Conversions	(220)			(220)
Deferred financing fees (net of amortization)	950			950
Balance, December 31, 2011	289,365			289,365
Assumed on acquisition⁽¹⁾ (Note 5)		158,471	158,343	316,814
Conversions and redemptions	(54)	(351)	(55)	(460)
Accretion of liability		841	688	1,529
Deferred financing fee (net amortization)	1,168	826	726	2,720
Balance, December 31, 2012	290,479	159,787	159,702	609,968

⁽¹⁾Excludes conversion feature of convertible debentures.

The Series C debentures may be converted at the option of the holder at a conversion price of $28.55 per share at any time prior to maturity and may be redeemed by the Company. The Company may, at its option after November 30, 2016, (or after November 30, 2014, provided that the volume weighted average trading price of the common shares on the TSX during the 20 consecutive trading days ending on the fifth trading day preceding the date on when the notice of redemption is given is not less than 125 percent of the conversion price of the debentures) elect to redeem the debentures by issuing shares. The Company may also elect to pay interest on the debentures by issuing shares.

The Series E debentures may be converted at the option of the holder at a conversion price of $24.94 per share at any time prior to maturity and may be redeemed by the Company. The Company may, at its option on or after December 31, 2013 and prior to December 31, 2015, elect to redeem the Series E debentures in whole or in part, provided that the volume weighted average trading price of the common price of the shares on the TSX during the 20 consecutive trading days ending on the fifth trading day preceding the date on which the notice of redemption is given is not less than 125 percent of the conversion price of the Series E debentures. On or after December 31, 2015, the Series E debentures may be redeemed in whole or in part at the option of the Company at a price equal to their principal amount plus accrued and unpaid interest. Any accrued unpaid interest will be paid in cash.

The Series F debentures may be converted at the option of the holder at a conversion price of $29.53 per share at any time prior to maturity and may be redeemed by the Company. The Company may, at its option on or after December 31, 2014 and prior to December 31, 2016, elect to redeem the Series F debentures in whole or in part, provided that the volume weighted average trading price of the common price of the shares on the TSX during the 20 consecutive trading days ending on the fifth trading day preceding the date on which the notice of redemption is given is not less than 125 percent of the conversion price of the Series F debentures. On or after December 31, 2016, the Series F debentures may be redeemed in whole or in part at the option of the Company at a price equal to their principal amount plus accrued and unpaid interest. Any accrued unpaid interest will be paid in cash.

The Company retains a cash conversion option on the Series E and F convertible debentures, allowing the Company to pay cash to the converting holder of the debentures, at the option of the Company. For convertible debentures with a cash conversion option, the conversion feature is recognized as an embedded derivative and accounted for as a derivative financial instrument, measured at fair value using an option pricing model.

14. PROVISIONS

The Company has estimated the net present value of its total decommissioning obligations based on a total future liability of $361.7 million (2011: $416.2 million). The estimate has applied a medium-term inflation rate and current discount rate and includes a revision in the decommissioning assumptions and associated costs and timing of payments. The obligations are expected to be paid over the next 75 years with majority being paid between 30 and 40 years. The Company applied a 2 percent inflation rate per annum (2011: 2.4 percent) and a risk free rate of 2.36 percent (2011: 2.49 percent) to calculate the present value of the decommissioning provision. During the year ended December 31, 2012, the Company estimated a decrease of $54.5 million (2011: increase of $134.5 million) in the total decommissioning obligation, including an increase of $124.6 million assumed on the Acquisition, offset by a $144.8 million decrease due to revised assumptions which the Company believes are more in line with industry, a $46.7 million decrease (2011: increase of $106.8 million) based on a change in the discount and inflation rates used to remeasure the obligation and $7 million (2011: $7.1 million) for unwinding of the discount rate, net of any settlements and a $5.4 million increase (2011: $20.6 million increase) representing the present value of additional obligations. The remeasured decommissioning provision decreased property, plant and equipment and decommissioning provision liability. $5.9 million of the re-measurement reduction in the decommissioning provision was in excess of the carrying amount of the related asset and is recognized as a credit to depreciation expense (2011: nil).

The property, plant and equipment of the Company consist primarily of underground pipelines, above ground equipment facilities and storage assets. No amount has been recorded relating to the removal of the underground pipelines or the storage assets as the potential obligations relating to these assets cannot be reasonably estimated due to the indeterminate timing or scope of the asset retirement. As the timing and scope of retirement become determinable for these assets, the fair value of the liability and the cost of retirement will be recorded.


($ thousands)	2012	2011
Balance at January 1	416,153	281,694
Unwinding of discount rate	11,956	10,141
Assumed on acquisition (Note 5)	124,579
Decommissioning liabilities settled during the period	(4,944)	(3,123)
Change in rates	(46,654)	106,793
Change in estimates and other	(139,352)	20,648
Total	361,738	416,153
Less current portion (included in accrued liabilities)	532	10,720
Balance at December 31	361,206	405,433

15. SHARE CAPITAL

Share capital

Pembina is authorized to issue an unlimited number of common shares and an unlimited number of a class of preferred shares designated as Preferred Shares, Series A. The holders of the common shares are entitled to receive notice of, attend at and vote at any meeting of the shareholders of the Company, receive dividends declared and share in the remaining property of the Company upon distribution of the assets of the Company among its shareholders for the purpose of winding-up its affairs.

Pembina has adopted a shareholder rights plan ("Plan") as a mechanism designed to assist the board in ensuring the fair and equal treatment of all shareholders in the face of an actual or contemplated unsolicited bid to take control of the company. Take-over bids may be structured in such a way as to be coercive or discriminatory in effect, or may be initiated at a time when it will be difficult for the board to prepare an adequate response. Such offers may result in shareholders receiving unequal or unfair treatment, or not realizing the full or maximum value of their investment in Pembina. The Plan discourages the making of any such offers by creating the potential of significant dilution to any offeror who does so.


($ thousands, except share amounts)	Number of Common Shares	Share Capital
Balance December 31, 2010	166,876,651	1,794,536
Share-based payment transactions	1,023,916	16,978
Debenture conversions and other	7,704	220
Balance December 31, 2011	167,908,271	1,811,734
Issued on acquisition (Note 5)	116,535,750	3,283,976
Share-based payment transactions	427,934	9,221
Dividend reinvestment plan	8,338,254	218,695
Debenture conversions and other	16,264	432
Balance December 31, 2012	293,226,473	5,324,058

Dividends

The following dividends were declared by the Company:


Year Ended December 31 ($ thousands)	2012	2011
$1.61 per qualifying common share (2011: $1.56 )	417,601	261,236

On January 8, 2013 and February 12, 2013, Pembina announced that the Board of Directors declared a dividend for each of January and February of $0.135 per qualifying common share ($1.62 annualized) in the total amount of $79.5 million.

16. REVENUES


Year Ended December 31 ($ thousands)	2012	2011
Rendering of Services:
Conventional pipeline transportation	338,772	296,190
Oil Sands and Heavy Oil pipeline transportation	172,429	134,874
Midstream and marketing terminalling, storage and hub services (net)	2,847,403	1,173,480
Gas services gathering and processing services	88,285	71,506
Intersegment eliminations	(19,487)
	3,427,402	1,676,050

17. COST OF SALES


Year Ended December 31 ($ thousands)	2012	2011
Operating expense	271,566	191,923
Cost of goods sold, including product purchases	2,475,038	1,072,270
Depreciation and amortization - operating	173,604	68,012
	2,920,208	1,332,205

18. GENERAL AND ADMINISTRATIVE EXPENSE


Year Ended December 31 ($ thousands)	2012	2011
Other general & administrative expense	91,706	59,984
Depreciation and amortization - general and administrative	5,782	2,207
	97,488	62,191

19. DEPRECIATION AND AMORTIZATION


Year Ended December 31 ($ thousands)	2012	2011
Cost of sales	173,604	68,012
General and administrative	5,782	2,207
	179,386	70,219

20. PERSONNEL EXPENSES


Year Ended December 31 ($ thousands)	2012	2011
Salaries and wages	82,350	57,564
Canada Pension Plan and EI remittances	2,436	1,717
Share-based payment transactions	17,028	18,651
Short-term incentive plan (bonus)	11,430	8,393
Defined contribution plan expense	1,685	878
Defined benefit pension plan expense	7,225	4,828
Health and dental benefit expense	3,459	2,232
Employee Savings plan expense	3,946	2,172
Other benefits	1,573	1,064
	131,132	97,499

21. NET FINANCE COSTS


Year Ended December 31 ($ thousands)		2012	2011
Interest income from:
Related parties		(262)	(876)
Bank deposits		(1,200)	(414)
Interest expense on financial liabilities measured at amortized cost:
	Loans and borrowings	72,956	56,722
	Convertible debentures	36,348	18,415
	Finance leases	426	404
	Unwinding of discount	12,021	10,141
(Gain) loss in fair value of non-commodity-related derivative financial instruments		(4,087)	7,619
Foreign exchange gains		(1,062)	(84)
Net finance costs		115,140	91,927

22. OPERATING SEGMENTS

The Company determines its reportable segments based on the nature of operations and includes four operating segments: Conventional Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream.

Conventional Pipelines consists of the tariff based operations of pipelines and related facilities to deliver crude oil, condensate and NGL in Alberta and B.C.

Oil Sands & Heavy Oil consists of the Syncrude, Horizon, Nipisi and Mitsue Pipelines, and the Cheecham Lateral. These pipelines and related facilities deliver synthetic crude oil produced from oil sands under long-term cost-of-service arrangements.

Gas Services consists of natural gas gathering and processing facilities, including three gas plants, twelve compressor stations and over 300 kilometres of gathering systems.

Midstream consists of the Company's interests in extraction and fractionation facilities, terminalling and storage hub services under a mixture of short, medium and long-term contractual arrangements.

The financial results of the business segments is included below. Performance is measured based on results from operating activities, net of depreciation and amortization, as included in the internal management reports that are reviewed by the Company's CEO, CFO and COO. The segments results from operating activities, before depreciation and amortization, is used to measure performance as management believes that such information is the most relevant in evaluating results of certain segments relative to other entities that operate within these industries. Intersegment transactions are recorded at market value and eliminated under corporate and intersegment eliminations.


Year Ended December 31, 2012 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream⁽²⁾	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	338,772	172,429			(19,487)	491,714
	NGL product and services, terminalling, storage and hub services				2,847,403		2,847,403
	Gas Services			88,285			88,285
Total revenue		338,772	172,429	88,285	2,847,403	(19,487)	3,427,402
	Operations	129,555	55,629	29,260	59,685	(2,563)	271,566
	Cost of goods sold, including product purchases				2,494,525	(19,487)	2,475,038
	Realized gain (loss) on commodity-related derivative financial instruments	111			(4,682)		(4,571)
Operating margin		209,328	116,800	59,025	288,511	2,563	676,227
	Depreciation and amortization (operational)	43,959	19,800	14,546	95,299		173,604
	Unrealized gain (loss) on commodity-related derivative financial instruments	(9,043)			45,143		36,100
Gross profit		156,326	97,000	44,479	238,355	2,563	538,723
	Depreciation included in general and administrative					5,782	5,782
	Other general and administrative	6,692	3,771	4,130	15,478	61,635	91,706
	Acquisition-related and other expenses (income)	957	297	11	434	23,049	24,748
Reportable segment results from operating activities		148,677	92,932	40,338	222,443	(87,903)	416,487
Net finance costs (income)		6,192	1,889	800	3,205	103,054	115,140
Reportable segment earnings (loss) before tax and income from equity accounted investees		142,485	91,043	39,538	219,238	(190,957)	301,347
Share of loss of investments in equity accounted investees, net of tax					1,056		1,056
Capital expenditures		187,264	30,432	162,838	203,969	(189)	584,314

⁽¹⁾		5.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
⁽²⁾		NGL product and services, terminalling, storage and hub services revenue includes $97.1 million associated with U.S. midstream sales.


Year Ended December 31, 2011 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	296,190	134,874				431,064
	Terminalling, storage and hub services				1,173,480		1,173,480
	Gas Services			71,506			71,506
Total revenue		296,190	134,874	71,506	1,173,480		1,676,050
	Operations	119,093	43,986	22,407	8,833	(2,396)	191,923
	Cost of goods sold, including product purchases				1,072,270		1,072,270
	Realized gain (loss) on commodity-related derivative financial instruments	4,413			882		5,295
Operating margin		181,510	90,888	49,099	93,259	2,396	417,152
	Depreciation and amortization (operational)	41,595	12,786	9,921	3,710		68,012
	Unrealized gain (loss) on commodity-related derivative financial instruments	3,743			1,433		5,176
Gross profit		143,658	78,102	39,178	90,982	2,396	354,316
	Depreciation included in general and administrative					2,207	2,207
	Other general and administrative	6,421	2,898	4,117	5,234	41,314	59,984
	Acquisition-related and other expenses (income)	1,018	(127)	6	2	530	1,429
Reportable segment results from operating activities		136,219	75,331	35,055	85,746	(41,655)	290,696
Net finance costs		7,110	1,729	999	109	81,980	91,927
Reportable segment earnings (loss) before tax and income from equity accounted investees		129,109	73,602	34,056	85,637	(123,635)	198,769
Share of loss (profit) of investments in equity accounted investees, net of tax					(5,766)		(5,766)
Capital expenditures		72,034	191,723	136,505	111,480	15,852	527,594

⁽¹⁾

4.8 percent of Conventional Pipelines revenue is under regulated tolling arrangements.

23. EARNINGS PER SHARE

Basic earnings per share

The calculation of basic earnings per share at December 31, 2012 was based on the earnings attributable to common shareholders of $224.8 million (2011: $165.7 million) and a weighted average number of common shares outstanding of 258.9 million (2011: 167.4 million).

Diluted earnings per share

The calculation of diluted earnings per share at December 31, 2012 was based on earnings attributable to common shareholders of $224.8 million (December 31, 2011: $165.7 million), and weighted average number of common shares outstanding after adjustment for the effects of all dilutive potential common shares of 259.5 million (2011: 168.2 million), calculated as follows:

Weighted average number of common shares


(In thousands of shares)	2012	2011
Issued common shares at January 1	167,908	166,877
Effect of shares issued on acquisition	87,243
Effect of share options exercised	185	556
Effect of conversion of convertible debentures	9
Effect of shares issued under dividend reinvestment plan	3,524
Weighted average number of common shares at December 31 (basic)	258,869	167,433

Dilutive effect of conversion of convertible debentures
Dilutive effect of share options on issue	614	742
Weighted average number of common shares at December 31 (diluted)	259,483	168,175

Basic earnings per share ($)	0.87	0.99
Diluted earnings per share ($)	0.87	0.99

At December 31, 2012, the effect of the conversion of the convertible debentures was excluded from the diluted earnings per share calculation as the impact was anti-dilutive. If the convertible debentures were included, an additional 23.3 million (2011: 10.5 million) common shares would be added to the weighted average number of common shares and $27.3 million (2011: $13.8 million) would be added to earnings, representing after tax interest expense of the convertible debentures.

The average market value of the Company's shares for purposes of calculating the dilutive effect of share options was based on quoted market prices for the period during which the options were outstanding.

24. CHANGES IN NON-CASH WORKING CAPITAL


Year Ended December 31 ($ thousands)	2012	2011
Accounts receivable, inventory and other	6,043	(30,388)
Accounts payable and accrued liabilities	(115,924)	10,091
Change in non-cash operating working capital	(109,881)	(20,297)

25. EMPLOYEE BENEFITS


December 31 ($ thousands)	2012	2011
Registered defined benefit obligation	21,394	10,755
Supplemental defined benefit obligation	6,180	5,092
Other accrued benefit obligations	1,049	1,104
Employee benefit obligations	28,623	16,951

The Company maintains a defined contribution plan and non-contributory defined pension plans covering its employees. The defined benefit plans include a funded registered plan for all employees and an unfunded supplemental retirement plan for those employees affected by the Canada Revenue Agency maximum pension limits. The Company also has other accrued benefit obligations which include a non-contribution unfunded post employment extended health and dental plan provided to a few remaining retired employees. Benefits under the plans are based on the length of service and the annual average best three years of earnings during last ten years of service of the employee. Benefits paid out of the plans are not indexed. The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation was at December 31, 2009.

Defined benefit obligations


December 31	2012		2011
($ thousands)	Registered Plan	Supplemental Plan	Registered Plan	Supplemental Plan
Present value of unfunded obligations		6,180		5,092
Present value of funded obligations	121,783		100,138
Total present value of obligations	121,783	6,180	100,138	5,092
Fair value of plan assets	100,389		89,383
Recognized liability for defined benefit obligations	(21,394)	(6,180)	(10,755)	(5,092)

The Company funds the defined benefit obligation plans in accordance with government regulations by contributing to trust funds administered by an independent trustee. The funds are invested primarily in equities and bonds. Defined benefit plan contributions totalled $10 million for the year ended December 31, 2012 (2011: $8 million).

The Company has determined that, in accordance with the terms and conditions of the defined benefit plans, and in accordance with statutory requirements of the plans, the present value of refunds or reductions in future contributions is not lower than the balance of the total fair value of the plan assets less the total present value of obligations. As such, no decreases in the defined benefit asset is necessary at December 31, 2012 and December 31, 2011.

Registered defined benefit pension plan assets comprise


December 31 (percentages)	2012	2011
Equity securities	65.1	64.1
Debt	30.1	30.8
Other	4.8	5.1
	100.0	100.0

Movement in the present value of the pension obligation

Year Ended December 31

2012

2011

($ thousands)

Registered
Plan

Supplemental
Plan

Registered
Plan

Supplemental
Plan

Defined benefits obligations at January 1

100,138

5,092

90,090

4,382

Benefits paid by the plan

(5,896)

(66)

(6,108)

Current service costs and interest

12,009

504

9,944

402

Actuarial losses in other comprehensive income

15,532

650

6,212

308

Defined benefit obligations at December 31

121,783

6,180

100,138

5,092

Movement in the present value of registered defined benefit pension plan assets


Year Ended December 31 ($ thousands)	2012	2011
Fair value of plan assets at January 1	89,383	89,609
Contributions paid into the plan	10,000	8,000
Benefits paid by the plan	(5,896)	(6,108)
Expected return on plan assets	5,288	5,521
Actuarial (losses) gains in other comprehensive income	1,614	(7,639)
Fair value of registered plan assets at December 31	100,389	89,383

Expense recognition in profit or loss

Year Ended December 31

2012

2011

($ thousands)

Registered
Plan

Supplemental
Plan

Registered
Plan

Supplemental
Plan

Current service costs

6,655

232

4,780

149

Interest on obligation

5,354

272

5,164

253

Expected return on plan assets

(5,288)

(5,521)

6,721

504

4,423

402

The expense is recognized in the following line items in the statement of comprehensive income:

Year Ended December 31

2012

2011

($ thousands)

Registered
Plan

Supplemental
Plan

Registered
Plan

Supplemental
Plan

Operating expenses

3,734

2,771

General and administrative expense

2,987

504

1,652

402

6,721

504

4,423

402

Actual return on plan assets

6,902

(2,118)

Actuarial gains and losses recognized in other comprehensive income

2012

2011

($ thousands)

Registered
Plan

Supplemental
Plan

Total

Registered
Plan

Supplemental
Plan

Total

Cumulative amount at January 1

15,050

146

15,196

4,662

(85)

4,577

Recognized during the period after tax

10,439

488

10,927

10,388

231

10,619

Cumulative amount at December 31

25,489

634

26,123

15,050

146

15,196

Principal actuarial assumptions used as at December 31 (expressed as weighted averages):


	2012	2011
Discount rate	4.4%	5.2%
Expected long-term rate of return on plan assets	5.8%	6.1%
Future pension earning increases	4.0%	4.0%

Assumptions regarding future mortality are based on published statistics and mortality tables. The current longevities underlying the values of the liabilities in the defined plans are as follows:


December 31 (years)	2012	2011
Longevity at age 65 for current pensioners
Males	19.8	19.7
Females	22.1	22.1

Longevity at age 65 for current member aged 45
Males	21.3	21.2
Females	22.9	22.9

The calculation of the defined benefit obligation is sensitive to the discount rate, compensation increases, retirements and termination rates as set out above. An increase or decrease of the estimated discount rate of 4.4 percent by 100 basis points at December 31, 2012 is considered reasonably possible in the next financial year. A discount rate of 5.4 percent would decrease the obligation by $18.2 million. A discount rate of 3.4 percent would increase the obligation by $23.2 million.

The overall expected long-term rate of return on assets is 5.8 percent. The expected long-term rate of return is based on the portfolio as a whole and not the sum of the returns on individual asset categories. The return is based exclusively on historical returns, without adjustments.

Historical information


December 31	2011		2010
($ thousands)	Registered Plan	Supplemental Plan	Registered Plan	Supplemental Plan
Present value of the defined benefit obligation	100,138	5,092	90,090	4,382
Fair value of plan assets	89,383		89,609
(Deficit) in the plan	(10,755)	(5,092)	(481)	(4,382)
Experience adjustments arising on plan liabilities			886	356
Experience adjustments arising on plan assets	7,639		(2,968)

December 31	2009		2008
($ thousands)	Registered Plan	Supplemental Plan	Registered Plan	Supplemental Plan
Present value of the defined benefit obligation	76,873	4,110	58,359	3,000
Fair value of plan assets	78,852		60,682
(Deficit)/surplus in the plan	1,979	(4,110)	2,323	(3,000)
Experience adjustments arising on plan liabilities	1,402	(14)		211
Experience adjustments arising on plan assets	(7,417)		17,702

The Company expects $12.6 million in contributions to be paid to its defined benefit plans in 2013.

26. SHARE-BASED PAYMENTS

At December 31, 2012, the Company has the following share-based payment arrangements:

Share option plan (equity settled)

The Company has a share option plan under which employees are eligible to receive options to purchase shares in the Company.

Long-term share unit award incentive (cash-settled) plan

In 2005, the Company established a long-term share unit award incentive plan. Under the share-based compensation plan, awards of restricted (RSU) and performance (PSU) share units are made to officers, non-officers and directors. The plan results in participants receiving cash compensation based on the value of the underlying notional shares granted under the plan. Payments are based on a trading value of the Company's common shares plus notional dividends and performance of the Company.

Terms and conditions of share option plan and share unit award incentive plan

The terms and conditions relating to the grants of the share option program and the long-term share unit award incentive plans are listed in the tables below:


Grant date share options granted to employees (Number of units in thousands)	Number of options in thousands	Contractual life of options
August 3, 2011	1,052	7 years
October 1, 2011	48	7 years
January 3, 2012	55	7 years
April 2, 2012	19	7 years
August 9, 2012	1,372	7 years
October 1, 2012	49	7 years

One third vest on the first anniversary of the grant date, one third vest on the second anniversary of the grant date, and one third vest on the third anniversary of the grant date.

Long-term share unit award incentive plan⁽¹⁾


Grant date PSUs to Officers, Non-Officers⁽²⁾ and Directors (Number of units in thousands)	Units	Contractual life of PSU
January 1, 2011	284	3.0 years
January 1, 2012	188	3.0 years
April 2, 2012 (on acquisition)	201	2.2 years

Vest on the third anniversary of the grant date. Actual PSUs awarded is based on the trading value of the shares and performance of the Company.


Grant date RSUs to Officers, Non-Officers⁽²⁾ and Directors (Number of units in thousands)	Units	Contractual life of RSU
January 1, 2011	185	3.0 years
January 1, 2012	186	3.0 Years
April 2, 2012 (on acquisition)	177	2.2 Years

One third vest on the first anniversary of the grant date, one third vest on the second anniversary of the grant date, and one third vest on the third anniversary of the grant date.

⁽¹⁾		Distribution Units are granted in addition to RSU and PSU grants based on notional accrued dividends from RSU and PSU granted but not paid.
⁽²⁾		Non-Officers defined as senior selected positions within the Company.

Disclosure of share option plan

The number and weighted average exercise prices of share options as follows:


	Number of Options	Weighted Average Exercise Price
Outstanding at December 31, 2010	2,759,259	16.43
Granted	1,100,800	25.29
Exercised	(1,023,916)	15.48
Forfeited	(161,763)	19.75
Outstanding at December 31, 2011	2,674,380	20.24
Granted	1,495,050	26.70
Exercised	(427,934)	16.96
Forfeited or expired	(209,858)	24.73
Outstanding as at December 31, 2012	3,531,638	23.11

As of December 31, 2012, the following options are outstanding:


Exercise Price (dollars)	Number outstanding at December 31, 2012	Options Exercisable	Weighted average remaining life (years)
$14.18 - $17.99	589,433	589,433	1.5
$18.00 - 20.99	593,380	369,124	4.6
$21.00 - $30.06	2,348,825	288,723	6.2

The weighted average share price at the date of exercise for share options exercised in the year ended December 31, 2012 was $28.28 (December 31, 2011: $24.64).

Expected volatility estimated by considering historic average share price volatility. The weighted average inputs used in the measurement of the fair values at grant date of share options are the following:

Share options granted


Year ended December 31
(dollars)		2012	2011
Weighted average
	Fair value at grant date	$2.10	$2.72
	Share price at grant date	$26.68	$25.72
	Exercise price	$26.70	$25.29
	Expected volatility	21.4%	24.7%
	Expected option life (years)	3.67	3.67
Expected annual dividends per option		$1.61	$1.56
Expected forfeitures		7.9%	7.0%
Risk-free interest rate (based on government bonds)		1.3%	1.6%

Disclosure of long-term share unit award incentive plan

The long-term share unit award incentive plan was valued using the reporting date market price of the Company's shares of $28.46 (December 31, 2011: $29.66). Actual payment may differ from amount valued based on market price and company performance.

Long-term share unit award incentive units granted


Year ended December 31	2012	2011
Number of share units granted	752,187	469,253

Employee expenses


($ thousands)	2012	2011
Share option plan, equity settled	1,828	1,097
Long-term share unit award incentive plan	15,200	17,554
Total expense recognized as employee costs	17,028	18,651

Total carrying amount of liabilities for cash settled arrangements	33,506	22,971
Total intrinsic value of liability for vested benefits	16,267	8,911

27. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

Economic hedges

The Company has entered into derivative financial instruments to limit the exposures to changes in commodity prices, interest rates, cost of power and foreign currency exchange rates. Hedge accounting has not been applied, however the Company still considers that there is an economic hedge which limits the exposure to fluctuations in revenue and expenses.

Financial risk

The Company has exposure to credit risk, liquidity risk and market risk. The Company's Board of Directors has the overall responsibility for the oversight of these risks and reviews the Company's policies on an ongoing basis to ensure that these risks are appropriately managed. The Company's Audit Committee oversees how management monitors compliance with the Company's risk management policies and procedures and reviews the adequacy of this risk framework in relation to the risks faced by the Company. The Company's Risk Management function assists in managing these risks. The Company's primary risk management objective is to protect capital resources, earnings and cash flow.

Counterparty credit risk

Counterparty credit risk is the risk of financial loss to the Company if a customer, partner or counterparty to a financial instrument failed to meet its contractual obligations in accordance with the terms and conditions of the financial instruments with the Company and which arise primarily from the Company's cash and cash equivalents, trade and other receivables, and from counterparties to its derivative financial instruments. The carrying amount of the financial assets represents the maximum credit exposure to the Company. The maximum counterparty credit exposure to counterparty credit risk at the reporting date was:


	Carrying Amount
December 31 ($ thousands)	2012	2011
Cash and cash equivalents	27,336
Trade and other receivables	334,772	159,081
Derivative financial instruments	7,871	6,450
	369,979	165,531

The Company manages counterparty credit risk for its cash and cash equivalents by maintaining bank accounts with Schedule 1 banks. The Company has minimal counterparty credit risk related to its receivables as a majority of these amounts are with large established counterparties in the oil and gas industry and are subject to the terms of the Company's shipping rules and regulations or pursuant to contracts. The rules and regulations permit the Company to receive and hold financial assurances against a counterparty to cover current and aged receivables when warranted. Balances are generally payable the 25th day of the following month. This date coincides with the date on which oil and gas companies receive payment from industry partners and counterparties. Typically, the Company has collected its receivables in full and at December 31, 2012, approximately 93 percent were current. The Company also maintains lien rights on the oil and NGL that are in its custody during the transportation of such products on the pipeline as well as the right to offset for single shipper operations. Therefore, the risk of non-collection is considered to be low and no impairment of receivables has been made.

Additionally, counterparty credit risk is mitigated through established credit management techniques, including conducting comprehensive financial and other assessments for all new counterparties and regular reviews of existing counterparties to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits, using contract netting arrangements and obtaining financial assurances when warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. The Company believes these measures minimize its counterparty credit risk but there is no certainty that they will protect it against all material losses. Letters of credit mitigate the counterparty credit risk on $44.6 million (December 31, 2011: $7.8 million) of the receivables balance. The Company's assessment of a counterparty's creditworthiness includes external credit ratings, where available, and in other cases, detailed financial and other assessments which generate an internal credit rating based on financial ratios. Counterparty exposure limits are established for each counterparty representing the maximum unsecured dollar amount in conjunction with an associated counterparty exposure limit approval authority matrix which has been approved by the Risk Management Committee. The Company continues to closely monitor and reassess its counterparty exposure limits on an ongoing basis.

Liquidity risk

Liquidity risk is the risk the Company will not be able to meet its financial obligations as they come due. The following are the contractual maturities of financial liabilities, including estimated interest payments and excluding the impact of netting agreements.


				Outstanding balances due by period
December 31, 2012 ($ thousands)	Carrying Amount	Expected Cash Flows	6 Months or Less	6 - 12 Months	1 - 2 Years	2 - 5 Years	More Than 5 Years
Trade payables and accrued liabilities	344,208	344,208	344,208
Loans and borrowings	1,938,626	2,446,733	44,927	35,637	312,765	693,389	1,360,015
Finance lease liabilities	5,800	7,101	1,327	1,327	1,823	2,624
Convertible debentures	609,968	903,475	19,607	19,607	39,360	291,204	533,697
Dividends payable	39,586	39,586	39,586
Derivative financial liabilities	67,691	67,691	11,532	4,400	16,774	25,115	9,870


				Outstanding balances due by period
December 31, 2011 ($ thousands)	Carrying Amount	Expected Cash Flows	6 Months or Less	6 - 12 Months	1 - 2 Years	2 - 5 Years	More Than 5 Years
Bank overdraft	676	676	676
Trade payables and accrued liabilities	155,926	155,926	155,926
Unsecured notes and credit facilities	1,272,838	1,663,644	27,120	340,285	350,445	117,494	828,300
Senior secured notes	57,499	70,909	6,257	6,257	25,027	33,368
Finance lease liabilities	5,650	7,742	1,273	1,273	1,942	3,254
Convertible debentures	289,365	299,780					299,780
Dividends payable	21,828	21,828	21,828
Derivative financial liabilities	17,539	18,460	2,385	2,385	3,670	6,438	3,582

The Company's approach to managing liquidity risk is to ensure funds and credit facilities are available to meet its short-term obligations. Management monitors daily cash positions and performs cash forecasts weekly to determine cash requirements. On a monthly basis, Management typically forecasts cash flows for a period of 12 months to identify financing requirements. These financing requirements are then addressed through a combination of credit facilities and through access to capital markets if required.

Market risk

Market risk is the risk that the fair value of a financial instrument will fluctuate because of changes in market prices. Market risk is generally comprised of price risk, currency risk and interest rate risk.

a. Price risk

Commodity price volatility and market location differentials affect the Midstream business. In addition, Midstream is exposed to possible price declines between the time Pembina purchases NGL feedstock and sells NGL products, and to narrowing frac spreads. Frac spreads are the difference between the selling prices for propane-plus and the input cost of the natural gas required to produce the respective NGL products.

Pembina responds to these risks using a market risk management program to protect margins on a portion of its natural gas based supply sales contracts, and to manage physical contract exposure while retaining some ability to participate in a widening margin environment. The Company uses derivative financial instruments to manage exposure to commodity prices and power costs. The Company does not trade financial instruments for speculative purposes. The derivative instruments include participating swaps and fixed price swap contracts that settle against indexed reference pricing. Participating swaps are contracts that provide a floor and ceiling for a certain percentage of the volume of a contract. A swap contract is an agreement where a floating price is exchanged for a fixed price over a specified period.

b. Currency risk

Pembina's commodity sales are exposed to both positive and negative effects of fluctuations in the Canadian/U.S. exchange rate. Pembina manages this exposure by matching a significant portion of the cash costs that it expects with revenues in the same currency. In addition, Pembina uses derivative instruments to manage the U.S. cash requirements of its business.

Pembina regularly sells or purchases a portion of expected U.S. cashflows. Pembina's also manages the exposure it has to fluctuations in the U.S./Canadian dollar exchange rate when the underlying commodity price is based upon a U.S. index price. Pembina may also use derivative products that provide for protection against a stronger Canadian dollar, while allowing it to participate if the currency weakens relative to the U.S. dollar.

c. Interest rate risk

At the reporting date, the interest rate profile of the Company's interest-bearing financial instruments was:


($ thousands)	Carrying Amounts of Financial Liability
December 31	2012	2011
Fixed rate instruments	(1,417,950)	(1,324,758)
Variable rate instruments	(520,675)	(319,465)

The Company uses swap contracts to manage exposure to variable interest rates.

Cash flow sensitivity analysis for variable rate instruments

A change of 100 basis points in interest rates at the reporting date would have (increased) decreased profit or loss by the amounts shown below. This analysis assumes that all other variables remain constant.


December 31($ thousands)	2012	2011
	± 100 bp	± 100 bp
Variable rate instruments	± 5,250	± 3,149
Interest rate swap	± (3,800)	± (2,000)
Profit or loss sensitivity (net)	± 1,450	± 1,149

Fair values

The fair values of financial assets and liabilities, together with the carrying amounts shown in the statement of financial position, are as follows:

December 31

2012

2011

($ thousands)

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Financial assets carried at fair value

Derivative financial instruments

7,871

6,450

Financial assets carried at amortized cost

Cash and cash equivalents

27,336

Trade and other receivables

334,772

159,081

362,108

159,081

Financial liabilities carried at fair value

Derivative financial instruments

67,691

17,538

Financial liabilities carried at amortized cost

Bank overdraft

676

Trade payables and accrued liabilities

344,208

155,926

Finance lease liabilities

5,800

6,170

5,650

5,948

Dividends payable

39,586

21,828

Loans and borrowings

1,938,626

2,083,505

1,272,838

1,391,895

Senior secured notes

57,499

65,567

Convertible debentures

609,968⁽¹⁾

725,074

289,365

326,760

2,938,188

3,198,543

1,803,782

1,968,600

⁽¹⁾ Carrying amount excludes conversion feature of convertible debentures.

The basis for determining fair values is disclosed in Note 4.

Interest rates used for determining fair value

The interest rates used to discount estimated cash flows, when applicable, are based on the government yield curve at the reporting date plus and adequate credit spread, and were as follows:


December 31	2012	2011
Derivatives	1.2% - 2.5%	1.1% - 1.8%
Loans and borrowings	2.0% - 3.7%	2.2% - 4.2%
Leases	4.4%	4.8%

Fair value of power derivatives are based on market rates reflecting forward curves.

Fair value hierarchy

The fair value of financial instruments carried at fair value is classified according to the following hierarchy based on the amount of observable inputs used to value the instruments.

Level 1: Unadjusted quoted prices are available in active markets for identical assets or liabilities as the reporting date. Pembina does not use Level 1 inputs for any of its fair value measurements.

Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices). Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices. Pembina obtains quoted market prices for commodities, future power contracts, interest rates and foreign exchange rates from information sources including banks, Bloomberg Terminals and Natural Gas Exchange (NGX). With the exception of one item described under Level 3, all of Pembina's financial instruments carried at fair value are valued using Level 2 inputs.

Level 3: Valuations in this level require the most significant judgments and consist primarily of unobservable or non-market based inputs. Level 3 inputs include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value. The redemption liability related to Three Star is classified as a Level 3 instrument, as the fair value is determined by using inputs that are not based on observable market data. The liability represents a put option, held by the non-controlling interest of Three Star, to sell the remaining one-third of the business to Pembina after the third anniversary of the original acquisition date (October 3, 2014). The put price to be paid by the Company for the residual interest upon exercise is based on a multiple of Three Star's earnings during the three year period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates. These estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.

Financial instruments classified as Level 3


($ thousands)	2012	2011
Redemption liability, beginning of year
Assumed on acquisition	6,183
Accretion of liability	65
Gain on revaluation	(962)
Redemption liability, end of year	5,286

The following table is a summary of the net derivative financial instrument liability:


As at December 31 ($ thousands)		2012	2011
Frac spread related		(3,068)
Product margin		(1,088)	2,267
Corporate
	Power	(7,100)	4,183
	Interest rate	(14,302)	(17,538)
	Foreign exchange	653
Other derivative financial instruments
	Conversion feature of convertible debentures (Note 13)	(29,629)
	Redemption liability related to acquisition of subsidiary	(5,286)
Net derivative financial instruments liability		(59,820)	(11,088)

In conjunction with the Acquisition, the Company assumed all of the rights and obligations of Provident relating to the Provident Debentures which included a $29.7 million liability for the conversion feature of the Provident Debentures. These convertible debentures contain a cash conversion option which is measured at fair value through profit and loss at each reporting date, with any unrealized gains or losses arising from fair value changes reported in the consolidated statement of comprehensive income. This resulted in the Company recording a gain of $0.1 million on the revaluation on the conversion feature of convertible debentures in profit and loss in net finance costs for the year ended December 31, 2012.


Commodity-Related Derivative Financial Instruments	Year Ended December 31
($ thousands)	2012	2011
Realized (loss) gain on commodity-related derivative financial instruments
Frac spread related	(4,497)
Product margin	(141)	882
Power	67	4,413
Realized (loss) gain on commodity-related derivative financial instruments	(4,571)	5,295
Unrealized gain on commodity-related derivative financial instruments	36,100	5,176
Gain on commodity-related derivative financial instruments	31,529	10,471

For non-commodity-related derivative financial instruments see Note 21, Net Finance Costs.

Sensitivity analysis

The following table shows the impact on earnings if the underlying risk variables of the derivative financial instruments changed by a specified amount, with other variables held constant.


As at December 31, 2012 ($ thousands)			+ Change	- Change
Frac spread related
	Natural gas	(AECO +/- $1.00 per GJ)	6,724	(6,724)
	NGL (includes propane, butane)	(Belvieu +/- U.S. $0.10 per gal)	(3,991)	3,991
	Foreign exchange (U.S.$ vs. Cdn$)	(FX rate +/- $0.05)	(3,637)	3,637
Product margin
	Crude oil	(WTI +/- $5.00 per bbl)	(6,387)	6,387
	NGL (includes propane, butane and condensate)	(Belvieu +/- U.S. $0.10 per gal)	6,112	(6,112)
Corporate
	Interest rate	(Rate +/- 50 basis points)	3,857	(3,857)
	Power	(AESO +/- $5.00 per MW/h)	3,631	(3,631)
Conversion feature of convertible debentures		(Pembina share price +/- $0.50 per share)	(2,761)	2,629

28. OPERATING LEASES

Leases as lessee

Operating lease rentals are payable as follows:


December 31 ($ thousands)	2012	2011
Less than 1 year	22,754	6,237
Between 1 and 5 years	109,542	20,021
More than 5 years	153,574	40,494
	285,870	66,752

The Company leases a number of offices, warehouses, vehicles and rail cars under operating leases. The leases run for a period of one to fifteen years, with an option to renew the lease after that date. The Company has sublet office space up to 2022 and has contracted sub-lease payments of $51.4 million over the term.

During the year ended December 31, 2012, an amount of $7.1 million was recognized as an expense in profit or loss in respect of operating leases (December 31, 2011: $3.8 million).

29. CAPITAL MANAGEMENT

The Company's objective when managing capital is to safeguard the Company's ability to provide a stable stream of dividends to shareholders that is sustainable over the long-term. The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and risk characteristics of its underlying asset base and based on requirements arising from significant capital development activities. Pembina manages and monitors its capital structure and short-term financing requirements using Non-GAAP measures; the ratios of debt to EBITDA, debt to Enterprise Value (market value of common shares and convertible debentures), adjusted cash flow to debt and debt to equity. The metrics are used to measure the Company's overall debt position and measure the strength of the Company's balance sheet. The Company remains satisfied that the leverage currently employed in the Company's capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base. The Company, upon approval from its Board of Directors, will balance its overall capital structure through new equity or debt issuances as required.

The Company maintains a conservative capital structure that allows it to finance its day-to-day cash requirements through its operations, without requiring external sources of capital. The Company funds its operating commitments, short-term capital spending as well as its dividends to shareholders through this cash flow, while new borrowing and equity issuances are reserved for the support of specific significant development activities. The capital structure of the Company consists of shareholder's equity plus long-term liabilities. Long-term debt is comprised of bank credit facilities, unsecured notes, finance lease obligations and convertible debentures.

Pembina is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants as of December 31, 2012.

Note 15 of these financial statements demonstrates the change in Share Capital for the year ended December 31, 2012.

30. GROUP ENTITIES

Significant subsidiaries


	Ownership Interest
December 31 (percentages)		2012	2011
Pembina Pipeline		100	100
Pembina Gas Services Limited Partnership		100	100
Pembina Oil Sands Pipeline LP		100	100
Pembina Midstream Limited Partnership		100	100
Pembina North Limited Partnership		100	100
Pembina West Limited Partnership		100	100
Pembina NGL Corporation		100
Pembina Facilities NGL LP		100
Pembina Infrastructure and Logistics LP		100
Pembina Empress NGL Partnership		100
Pembina Resource Services Canada		100
Pembina Resource Services (U.S.A.)		100
Three Star Trucking Ltd.		67

31. RELATED PARTIES

All transactions with related parties were made on terms equivalent to those that prevail in arm's length transactions.

Investments in equity accounted investees

Officers of Pembina Pipeline Corporation, the ultimate controlling party, are Directors of Fort Saskatchewan Ethylene Storage Corporation ("FSESC"), the parent of Fort Saskatchewan Ethylene Storage Limited Partnership ("FSESLP"). FSESLP and FSESC are both recognized as investments in joint ventures under the equity method on Pembina's financial statements. Results from operating activities are recorded as Share of Profit from Equity Accounted Investees on Pembina's Statement of Comprehensive Income, representing a 50 percent interest in the joint ventures.

($ thousands)

Transaction Value
Year Ended December 31

Balance Outstanding
As At December 31

2012

2011

2012

2011

Related Party

Transaction

Note

FSESLP

Interest revenue

262

876

Loan receivable

17,903

Key management personnel and director compensation

Key management consists of the Company's directors and certain key officers.

Compensation

In addition to short-term employee benefits - including salaries, director fees and bonuses - the Company also provides key management personnel with share-based compensation, contributes to post employment pension plans and provides car allowances, parking and business club memberships.

Key management personnel compensation comprised:


Year Ended December 31 ($ thousands)	2012	2011
Short term employee benefits	2,743	2,802
Post-employment benefits	231	207
Share-based compensation	5,806	6,150
Other compensation	121	112
Total compensation of key management	8,901	9,271

Transactions

Key management personnel and directors of the Company control 0.5 percent (2011: 0.8 percent) of the voting common shares of the Company. Certain directors and key management personnel also hold Pembina convertible debentures. Dividend and interest payments received for the common shares and debentures held are commensurate with other non-related holders of those instruments.

Certain officers are subject to employment agreements in the event of termination without just cause or change of control.

Post employment benefit plans

Pembina has significant influence over the pension plans for the benefit of their respective employees.

Transactions

($ thousands)

Transaction Value
Year Ended December 31

Balance Outstanding
As At December 31

Post-employment
benefit plan

Transaction

2012

2011

2012

2011

Defined benefit plan

Funding

10,000

8,000

CORPORATE INFORMATION
_______________________________________________________________________________

HEAD OFFICE

Pembina Pipeline Corporation
Suite 3800, 525 - 8th Avenue S.W.
Calgary, Alberta T2P 1G1

AUDITORS

KPMG LLP
Chartered Accountants
Calgary, Alberta

TRUSTEE, REGISTRAR & TRANSFER AGENT

Computershare Trust Company of Canada
Suite 600, 530 - 8th Avenue SW
Calgary, Alberta T2P 3S8
1-800-564-6253

STOCK EXCHANGE

Pembina Pipeline Corporation
TSX listing symbols for:
Common shares: PPL
Convertible debentures: PPL.DB.C, PPL,DB.E, PPL.DB.F

NYSE listing symbol for:
Common shares: PBA

INVESTOR INQUIRIES

Phone: (403) 231-3156
Fax: (403) 237-0254
Toll Free: 1-855-880-7404
Email: [email protected]
Website: www.pembina.com